Petroleum Geology and Resources of the 

Middle Caspian Basin, Former Soviet Union

By Gregory F. Ulmishek

U.S. Geological Survey Bulletin 2201–A

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

Gale A. Norton, Secretary

U.S. Geological Survey

Charles G. Groat, Director

This publication is only available online at:

http://geology.cr.usgs.gov/pub/bulletins/b2201–a

Any use of trade, product, or firm names in this publication

is for descriptive purposes only and does not imply 

endorsement by the U.S. Government

Manuscript approved for publication March 23, 2001

Published in the Central Region, Denver, Colorado

Graphics by Susan Walden

Photocomposition by Norma J. Maes

Edited by L.M. Carter

Version 1.0, 2001
III

Contents

Foreword................................................................................................................................................ 1

Abstract ................................................................................................................................................. 1

Introduction........................................................................................................................................... 3

Province Overview .............................................................................................................................. 3

 Province Location and Boundaries ........................................................................................... 3

 Tectono-Stratigraphic Sequences ............................................................................................ 3

 Structure ........................................................................................................................................ 5

 Petroleum Systems....................................................................................................................... 5

South Mangyshlak Total Petroleum System (110902), Middle Caspian Basin, 

 Kazakhstan............................................................................................................................... 7

 Introduction ................................................................................................................................... 7

 Discovery History.......................................................................................................................... 7

 Petroleum Occurrence ................................................................................................................ 7

 Stratigraphic Section ................................................................................................................... 9

 Source Rocks ................................................................................................................................ 12

 Reservoir Rocks............................................................................................................................ 13

 Seal Rocks ..................................................................................................................................... 13

 Traps ............................................................................................................................................... 13

 Assessment Units......................................................................................................................... 15

 Assessment Unit 11090201, South Mangyshlak (Entire) .................................................. 15

Terek-Caspian Total Petroleum System (110901), Middle Caspian Basin, Russia.................... 15

 Introduction.................................................................................................................................... 15

 Discovery History .......................................................................................................................... 15

 Petroleum Occurrence................................................................................................................. 16

 Stratigraphic Section.................................................................................................................... 18

 Source Rocks................................................................................................................................. 18

 Reservoir Rocks............................................................................................................................. 22

 Seal Rocks...................................................................................................................................... 22

 Traps................................................................................................................................................ 22

 Assessment Units.......................................................................................................................... 23

 Assessment Unit 11090101, Foldbelt-Foothills ................................................................... 23

 Assessment Unit 11090103, Foreland Slope and Foredeep............................................. 23

 Assessment Unit 11090102, Terek-Sunzha Subsalt Jurassic.......................................... 23

Stavropol-Prikumsk Total Petroleum System (110903), Middle Caspian Basin, Russia........... 25

 Introduction.................................................................................................................................... 25

 Discovery History .......................................................................................................................... 27

 Petroleum Occurrence................................................................................................................. 27

 Stratigraphic Section.................................................................................................................... 30

 Source Rocks................................................................................................................................. 30

 Reservoir Rocks. ........................................................................................................................... 33

 Seal Rocks. .................................................................................................................................... 35

 Traps................................................................................................................................................ 35

Assessment Units................................................................................................................................. 35

 Assessment Unit 11090302, Onshore Stavropol-Prikumsk ............................................. 35

 Assessment Unit 11090301, Offshore Prikumsk Zone....................................................... 36

 Assessment Unit 11090303, Central Caspian Offshore..................................................... 36

References Cited.................................................................................................................................. 36
IV

Figures

 1. Map showing petroleum systems and assessment units, Middle Caspian basin, 

 Province 1109 ............................................................................................................................... 2

 2. Generalized map showing main structural units of Middle Caspian basin........................ 4

 3. Cross section through Middle Caspian basin ......................................................................... 6

 4. Generalized map showing structural units of South Mangyshlak petroleum system...... 8

 5. Sketch map showing Triassic rift systems of South Mangyshlak ....................................... 9

 6. Cross section (southwest-northeast) through South Mangyshlak petroleum system .... 10

 7. Cross section (south-north) through South Mangyshlak petroleum system..................... 11

 8. South Mangyshlak petroleum system events chart .............................................................. 14

 9. Structural map of eastern North Caucasus region................................................................ 16

10. Cross sections through Terek-Sunzha and Dagestan thrust belts ...................................... 17

11. Columnar stratigraphic section of Mesozoic-Tertiary rocks of Terek-Caspian

 petroleum system......................................................................................................................... 19

12. Maps showing maturity zones in stratigraphic units of eastern North Caucasus

 region............................................................................................................................................. 20

13. Terek-Caspian petroleum system events chart...................................................................... 21

14. Columnar stratigraphic section of Mesozoic-Tertiary rocks of Stavropol-Prikumsk

 petroleum system......................................................................................................................... 26

15. Structural map of Triassic taphrogenic sequence of eastern North Caucasus region... 28

16. Cross section through Stavropol-Prikumsk petroleum system............................................ 29

17. Diagram showing maturation model for Kochubey 2 well.................................................... 31

18. Diagram showing maturation model for Gorokhov 9 well..................................................... 32

19. Stavropol-Prikumsk petroleum system events chart............................................................. 34

Tables

1. Middle Caspian basin, Province 1109— Assessment results summary – allocated

 resources .................................................................................................................................. 24
1

 Foreword

This report was prepared as part of the World Energy 

Project of the U.S. Geological Survey. In the project, the world 

was divided into 8 regions and 937 geologic provinces. The 

provinces have been ranked according to the discovered oil and 

gas volumes within each (U.S. Geological Survey World Energy 

Assessment Team, 2000). Then, 76 “priority” provinces 

(exclusive of the U.S. and chosen for their high ranking) and 26 

“boutique” provinces (exclusive of the U.S. and chosen for their 

anticipated petroleum richness or special regional economic 

importance) were selected for appraisal of oil and gas resources. 

The petroleum geology of these priority and boutique provinces 

is described in this series of reports.

The purpose of this effort is to aid in assessing the quantities of oil, gas, and natural gas liquids that have the potential to 

be added to reserves within the next 30 years. These volumes 

either reside in undiscovered fields whose sizes exceed the stated 

minimum-field-size cutoff value for the assessment unit (variable, but must be at least 1 million barrels of oil equivalent) or 

occur as reserve growth of fields already discovered. 

The petroleum system constitutes the basic geologic unit of 

the oil and gas assessment. The total petroleum system includes 

all genetically related petroleum found in shows and accumulations (discovered and undiscovered) that has been generated by a 

pod or by closely related pods of mature source rock. This petroleum exists within a limited mappable geologic space, together 

with the essential mappable geologic elements (source, reservoir, 

and seal) that control the fundamental processes of generation, 

expulsion, migration, entrapment, and preservation of petroleum.

An assessment unit is a mappable part of a total petroleum 

system in which discovered and undiscovered fields constitute a 

single relatively homogeneous population such that the chosen 

methodology of resource assessment based on estimation of the 

number and sizes of undiscovered fields is applicable. A total 

petroleum system might equate to a single assessment unit. If 

necessary, a total petroleum system may be subdivided into two 

or more assessment units such that each assessment unit is sufficiently homogeneous in terms of geology, exploration considerations, and risk to assess individually.

A numeric code identifies each region, province, total 

petroleum system, and assessment unit; these codes are uniform 

throughout the project and will identify the same item in any of 

the publications. The code is as follows: 

Example

Region, single digit 3

Province, three digits to the right of region code 3162

Total petroleum system, two digits to the right of

 province code 316205

Assessment unit, two digits to the right of 

petroleum system code 31620504

The codes for the regions and provinces are listed in 

U.S. Geological Survey World Energy Assessment Team 

(2000).

Oil and gas reserves quoted in this report are derived from 

Petroleum Exploration and Production database (Petroconsultants, 1996) and other area reports from Petroconsultants, Inc., 

unless otherwise noted.

A map, figure 1 of this report, shows boundaries of the 

total petroleum systems, assessment units, and pods of active 

source rocks; it was compiled using geographic information 

system (GIS) software. Political boundaries and cartographic 

representations were taken, with permission, from Environmental Systems Research Institute’s ArcWorld 1:3 million digital 

coverage (1992), have no political significance, and are displayed for general reference only. Oil and gas field centerpoints, shown on this map, are reproduced, with permission, 

from Petroconsultants (1996). 

Abstract

The Middle Caspian basin occupies a large area between 

the Great Caucasus foldbelt and the southern edge of the Precambrian Russian craton. The basin also includes the central part 

of the Caspian Sea and the South Mangyshlak subbasin east of 

the sea. The basin was formed on the Hercynian accreted terrane 

during Late Permian–Triassic through Quaternary time. Structurally, the basin consists of the fold-and-thrust zone of the 

northern Caucasus foothills, the foredeep and foreland slope, the 

Stavropol-Prikumsk uplift and East Manych trough to the north 

of the slope, and the South Mangyshlak subbasin and slope of 

the Karabogaz arch east of the Caspian Sea. All these major 

structures extend offshore. 

Four total petroleum systems (TPS) have been identified in 

the basin. The South Mangyshlak TPS contains more than 40 

discovered fields. The principal reserves are in Lower–Middle 

Jurassic sandstone reservoirs in structural traps. Source rocks are 

poorly known, but geologic data indicate that they are in the Triassic taphrogenic sequence. Migration of oil and gas significantly postdated maturation of source rocks and was related to 

faulting and fracturing during middle Miocene to present time. A 

single assessment unit covers the entire TPS. Largest undiscovered resources of this assessment unit are expected in the largely 

undrilled offshore portion of the TPS, especially on the western 

plunge of the Mangyshlak meganticline.

Petroleum Geology and Resources of the Middle Caspian 

Basin, Former Soviet Union

By Gregory F. Ulmishek
2 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

Donbas Foldbelt

North Caspian Basin

Great Caucasus Foldbelt

Mangyshlak-Ustyurt Foldbelt

 ASSESSMENT DATA

Assessment units boundary and name

11090101

11090103

11090102

11090201

11090301

11090302

11090303

Total petroleum system boundary and 

name

Terek-Caspian

Stavropol-Prikumsk

South Mangyshlak

Shakpakhty

J

J

J

J Pod of active source rocks boundary—

 Ticks indicate side of their presence;

 -Triassic, J-Jurassic

EXPLANATION

Hydrography

Shoreline

Geologic province name 

and boundary

Gas field centerpoint

Oil field centerpoint

Projection: Equidistant Conic. Central meridian: 100. Standard Parallel: 58 30

South Caspian Basin

J

J

North Ustyurt Basin

Karabogaz-Karakum High

Kura Basin

Middle Caspian 

 Basin

 

Figure 1. Map showing petroleum systems and assessment units of Middle Caspian basin, Province 1109.

RT

RT

RT

RT

RT

RT

40° E

45° N

45° E 50° N

50° E

45° N

55° E

55° E

40° N

40° N

50° E

45° E

Country boundary

Kazakhstan

Russia

0 150 KILOMETERS

N
Introduction 3

The Terek-Caspian TPS occupies the fold-and-thrust belt, 

foredeep, and adjoining foreland slope. About 50 hydrocarbon 

fields, primarily oil, have been discovered in the TPS. Almost all 

hydrocarbon reserves are in faulted structural traps related to 

thrusting of the foldbelt, and most traps are in frontal edges of 

the thrust sheets. The traps are further complicated by plastic 

deformation of Upper Jurassic salt and Maykop series (Oligocene–lower Miocene) shale. Principal reservoirs are fractured 

Upper Cretaceous carbonates and middle Miocene sandstones. 

Principal source rocks are organic-rich shales in the lower part of 

the Maykop series. Source rocks may also be present in the 

Eocene, Upper Jurassic, and Middle Jurassic sections, but their 

contribution to discovered reserves is probably small. Three 

assessment units are delineated in the TPS. One of them encompasses the thrust-and-fold belt of northern Caucasus foothills. 

This assessment unit contains most of the undiscovered oil 

resources. The second assessment unit occupies the foredeep and 

largely undeformed foreland slope. Undiscovered resources of 

this unit are relatively small and primarily related to stratigraphic 

traps. The third unit is identified in almost untested subsalt Jurassic rocks occurring at great depths and is speculative. The unit 

may contain significant amounts of gas under the Upper Jurassic 

salt seal.

The Stavropol-Prikumsk TPS lies north of the Terek-Caspian TPS and extends offshore into the central Caspian Sea 

where geologic data are scarce. More than one hundred oil and 

gas fields have been found onshore. Offshore, only one well was 

recently drilled, and this well discovered a large oil and gas field. 

Almost the entire sedimentary section of the TPS is productive; 

however, the principal oil reserves are in Lower Cretaceous clastic reservoirs in structural traps of the Prikumsk uplift. Most 

original gas reserves are in Paleogene reservoirs of the Stavropol 

arch and these reservoirs are largely depleted. At least three 

source rock formations, in the Lower Triassic, Middle Jurassic, 

and Oligocene–lower Miocene (Maykop series), are present in 

the TPS. Geochemical data are inadequate to correlate oils and 

gases in most reservoirs with particular source rocks, and widespread mixing of hydrocarbons apparently took place. Three 

assessment units encompassing the onshore area of the TPS, the 

offshore continuation of the Prikumsk uplift, and the central Caspian area, are identified. The principal portion of undiscovered 

resources is assigned to the offshore Prikumsk zone where a 

large discovery was recently made (after this resource assessment had been completed).

The Shakpakhty TPS is small and located east of the South 

Mangyshlak subbasin. The TPS contains a single gas field, possesses very low potential, and has not been assessed.

Introduction

With 14.4 billion barrels of oil equivalent (BOE) of discovered hydrocarbon reserves, the Middle Caspian basin is ranked 

27th among 102 provinces designated for appraisal of undiscovered oil and gas resources by the U.S. Geological Survey (U.S. 

Geological Survey World Energy Assessment Team, 2000). The 

location and boundaries of the province are shown in figure 1. 

This report outlines the principal geologic features of the basin 

and defines its total petroleum systems (TPS) and assessment 

units (AU). Definitions of the TPS and AU are given in the Foreword of this report. The assessment technique and procedure are 

explained in U.S. Geological Survey World Energy Assessment 

Team (2000).

The first production in the basin was established as early as 

1893, when a well discovered oil in shallow middle Miocene 

sandstones near Groznyi, Russia. However, major discoveries in 

the basin were made in deeper Cretaceous and Jurassic rocks in 

the 1950’s and 1960. Peak production was reached in 1969–

1971, after which a gradual decline in production of both oil and 

gas began (Dikenshtein and others, 1983). Exploration in the 

basin has been almost entirely concentrated on land, and only a 

few wells have been drilled offshore. The first offshore oil and 

gas field (Inchkhe-more) was found in 1974 in the southeastern 

nearshore area, but several other prospects drilled in the 1980’s 

failed to discover commercial accumulations. In 2000, Russian 

company Lukoil announced discovery of a large (potentially 

more than 2 billlion BOE) oil and gas field in the north-central 

offshore area (Severny area) of the basin (The Wall Street Journal, 2000). The basin mostly lies in Russia and Kazakhstan; a 

small southwestern part of the basin is in Azerbaijan.

Province Overview

Province Location and Boundaries

The Middle Caspian basin occupies the eastern North Caucasus region, the central part of the Caspian Sea, and a system of 

depressions east of the sea (fig. 1). The southern basin boundary 

is defined by the Great Caucasus foldbelt, Karabogaz arch, and, 

in offshore areas, by the Apsheron sill (Apsheron-Pribalkhan 

zone of uplifts) separating the Middle Caspian and South Caspian basins (fig. 2). The northern boundary with the North Caspian basin extends along the Karpinsky Ridge (southeastern 

continuation of the Donbas foldbelt). Strongly deformed upper 

Paleozoic rocks of the ridge (foldbelt) are exposed on the surface 

in its western part and buried under Mesozoic and Tertiary rocks 

in the eastern part. Offshore, the boundary is defined by the 

southern limit of salt tectonics, and farther east it is drawn along 

the Mangyshlak and Central Ustyurt systems of uplifts (fig. 4). 

On the west, the Stavropol arch and Mineralovod high separate 

the Middle Caspian basin from the Azov-Kuban basin located 

farther west. On the Stavropol arch, the basement is overlain by 

Albian and younger rocks and older stratigraphic units pinch out 

on the slopes. Most of the basin is located in Russia (west of the 

Caspian Sea) and Kazakhstan (east of the sea). A small southern 

part of the western nearshore area is in Azerbaijan.

Tectono-Stratigraphic Sequences

Basement of the Middle Caspian basin is a Hercynian 

accreted terrane composed of various middle to late Paleozoic 

deformed rocks. The basement is overlain by the Late Permian–

Triassic rift system filled with clastic, carbonate, and volcanic 

rocks. Various parts of this taphrogenic sequence are unconformably overlain by a platform sequence of Jurassic through Eocene 

rocks. Lower–Middle Jurassic clastics, commonly enriched by 

coaly organic matter, occur at the base of this sequence. The 
4 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

B

A

N

Ap

S

s

il

h

l

eron

North

Apsheron

D

epression

Great Caucasus Foldbelt

Terek - Caspian

Foredeep

Uplift

Chernoles

Depression

Mineralovod

High

Stavropol Arch

Karpinsky

Ridge

East Manych

Trough

Agrakhan - Guryev Fault

North  B

Mangyshlak

Megant

South

Mangyshlak - Ustyur

Ce

ntral Caspian

Monocline

Peschanomys

Uplift

 KazakhDepression

K

a

r

a

NorthRakushechnoyeUplift

Uplift

Derbent

Boundary of major tectonic unitMain faultLine of cross section in figure 3

Figure 2. Generalized map showing main structural units of Middle Caspian basin (modified from Ulmishek and Harrison, 1981).

0

0

40

20

80

40 60

KILOMETERS

MILES

Caspian Sea

Terek River

Prikumsk

Ku ma River

EXPLANATION

A B

o 45 50° 
Province Overview 5

rocks are mainly continental in the lower part (except for a zone 

along the Great Caucasus), becoming progressively more marine 

to the top of the section. During the widespread transgression of 

middle Callovian-Kimmeridgian time, the sea deposited shales 

and carbonates. The Tithonian interval is represented by a significant unconformity in most areas except for the central TerekCaspian foredeep where thick salt was deposited in a deep-water 

lagoon that was separated by reefs from the Tethyan ocean to the 

south. Cretaceous rocks are dominantly marine and composed of 

Neocomian carbonates and clastics, a thick Aptian-Albian clastic section, and mostly carbonate Upper Cretaceous rocks. Paleocene-Eocene rocks at the top of the platform sequence are thick 

shallow-marine clastics on the Stavropol arch and a thin condensed section of deep-marine pelagic carbonates and shales 

east of the arch.

The orogenic sequence at the top of the sedimentary cover 

was deposited during formation of a foreland basin north of the 

growing Great Caucasus foldbelt. The sequence reaches its maximum thickness of 4–6 km in the foredeep along the mountain 

front. The sequence starts with the Oligocene–lower Miocene 

Maykop series—a thick shale section, which, in the northeastern 

areas, contains sandstone beds in its middle and upper parts. 

Deep-water black shales enriched by type II kerogen are ubiquitous in the lower part of the series and are an important source 

rock. Major provenance was still to the northeast of the basin, 

but numerous massive olistostromes (gravity flow deposits) are 

present along the Caucasus front. The olistostromes that include 

various chaotically mixed pre-Maykop rocks indicate the initial 

stage of Caucasus orogenic uplift, although the uplifted structures were still submerged. Clastic turbidites, including sandstones, derived from the south are known in the lower Maykop 

series in more western areas of North Caucasus, in the AzovKuban basin.

An important pre-middle Miocene unconformity at the top 

of the Maykop series records the beginning of the neotectonic 

stage. The stage was characterized by continuing compressive 

stress from the south, which affected the entire basin and 

extended far to the north into the Russian craton. The stress produced intense structural growth, faulting, and fracturing in many 

areas. Thick (to 2.5–3.5 km), coarsening-upward orogenic clastics deposited during this stage are limited to the narrow foredeep, and they abruptly thin to a few hundred meters and less 

across the foreland slope (fig. 3).

Structure

The Middle Caspian basin was formed in Jurassic-Cenozoic time on the epi-Hercynian late Paleozoic basement, which 

was cut by a number of near latitudinal Late Permian–Triassic 

rifts. The basin is tectonically heterogeneous; its western part is 

a typical foreland basin whereas formation of the eastern part is 

related to post-Triassic subsidence of a crustal block between 

two Permian-Triassic rifts (Ulmishek and Harrison, 1981). The 

northern rift was structurally inverted and strongly deformed in 

pre-Jurassic time. It is expressed as the Mangyshlak foldbelt 

(meganticline) in the present structure (fig. 2).

The main structural units of the basinal sedimentary cover 

are shown in figure 2. The principal structural grain parallels the 

Great Caucasus foldbelt, which was formed in post-Eocene time 

due to closing of the marginal sea in the northern Tethys. The 

deepest part of the basin is in the foredeep where depth to the 

basement reaches 10–12 km (fig. 3). From the foredeep, basement rises northward to the Stavropol arch and Karpinsky Ridge 

where it occurs at 1.5–2 km.

Available data on the structure of the central Caspian Sea 

are scarce because, until recently, few seismic surveys had been 

conducted there. During the last few years, a consortium of 

international oil companies shot a number of regional profiles 

across the northern and central parts of the sea, but results of this 

work are not in the public domain. Structures on both shores of 

the sea plunge offshore and lose expression. Apparently, eastern 

and western structural units (including Triassic rifts) are not continuous across the sea and are separated by the regional Agrakhan-Guryev fault, which can be interpreted as a pre-Jurassic 

strike-slip fault (fig. 2).

Petroleum Systems

The Middle Caspian basin contains at least four known 

total petroleum systems (TPS): (1) South Mangyshlak, (2) 

Terek-Caspian, (3) Stavropol-Prikumsk, and (4) Shakpakhty 

systems (fig. 1). Three of the four TPS of the basin extend into 

the Caspian Sea, where their dimensions are conjectural because 

only a few wells have been drilled offshore and only two potentially commercial discoveries have been made on the southern 

Dagestan shelf and in the north-central part of the sea. Assessed 

undiscovered oil and gas resources of three principal petroleum 

systems are shown in table 1.

The dominant petroleum reserves of the rich South Mangyshlak TPS are in Middle Jurassic sandstones in structural traps. 

Minor reserves are in Triassic carbonates and clastics in fields 

that are controlled by zones of fracturing. A few accumulations 

are known in Lower Cretaceous sandstones and in fractured 

basement granites. Source rocks are certainly present in the Triassic section, but their areal extent has not been mapped. Some 

hydrocarbons could have been generated from Lower–Middle 

Jurassic clastics, but their endowment in reserves, if any, is probably small.

The Terek-Caspian TPS is also rich in hydrocarbons, 

mainly oil. The principal reserves are in Upper Cretaceous fractured carbonates and middle Miocene sandstones. The fields are 

controlled by high-amplitude anticlines, which are related to 

thrusts and are complicated by deformation of Upper Jurassic 

salt and Oligocene–lower Miocene Maykop shales. The main 

source rocks are probably Maykop shales (Ulmishek and Harrison, 1981). An analogy with the geologically similar, neighboring Azov-Kuban and Amu-Darya basins suggests that source 

rocks may also be present in the subsalt Jurassic section.

The Stavropol-Prikumsk TPS contains large gas reserves in 

lower Maykop (Khadum Horizon) sandstones on the Stavropol 

arch and moderate oil and gas reserves mainly in Lower Cretaceous sandstones in anticlinal traps of the Prikumsk uplift and 
6 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

1 1+2

2

3

K

M

0 10 20 30 40 500 10 20 30

K1

K2

K1

K2

2

Figure 3. Cross section through Middle Caspian basin (modified from Dikenshtein and others, 1983). Location shown in figure 2. Although this figure shows 

anticlines are related to thrusts with decollement in Upper Jurassic evaporites. (See fig. 10.) P, Permian; 

, Triassic; J, Jurassic; K, Cretaceous; T, Tertiary; Q, 

3 denote lower, middle, and upper respectively. 

T2-Q T2-Q

J3 J3

J1+2

J1+2

J1-2

J1-2

J1+2

K2K1 K1

T1 T1

T1

T1

T2

P +

P +

K1

 2

 1

S.L. 0

 1 2 3 4 5 6 7 8 9

 10

 11

Km

Fault

Oil and gas pools

S

Terek-Caspian Foredeep Nogay Monocline Prikumsk Uplift East Manych Trou

Sunzha Ridge

Karabulak-Achaluki

Field

Terek Ridge

Ali-Yurt Field

Mekteb 

Field

Yuzhnoye

Field

Zimnyaya Stavka

Field

Ko

A

Basement

EXPLANATION



1
South Mangyshlak Total Petroleum System (110902), Middle Caspian Basin, Kazakhstan 7

adjacent structures. Minor reserves have been discovered in 

Jurassic clastics, Lower Triassic carbonates, and in self-sourced 

fractured shale reservoirs in the lower part of the Maykop series. 

Principal source rocks are difficult to identify. Probably they are 

Bajocian marine shales moderately rich in organic matter. 

Source rocks are also present in Lower Triassic and lower Maykop sections. When more geochemical data are available, two or 

three overlapping petroleum systems can probably be identified 

in the sedimentary section.

The Shakpakhty TPS is identified by the Shakpakhty gas 

field where three gas pools are reservoired in Middle Jurassic 

clastic rocks. Source rocks for the gas are unknown. A number 

of other structural prospects have been drilled in the area, but no 

commercial accumulations or even significant shows have been 

found. The petroleum potential of the system is low, and it is not 

assessed or further described in this report.

South Mangyshlak Total Petroleum System 

(110902), Middle Caspian Basin, Kazakhstan

Introduction

The South Mangyshlak total petroleum system (TPS) is 

located in the eastern part of the Middle Caspian basin, east of 

the Caspian Sea (fig. 1). On the north and northeast, the system 

is bounded by the Mangyshlak foldbelt, which is a structurally 

inverted and deformed axial zone of the Triassic rift. On the 

south, the TPS borders the Karabogaz arch where thin Cretaceous and Tertiary rocks overlie the basement. To the west, the 

TPS extends into the central Caspian Sea where its dimension is 

unknown. Possibly, it extends to the Agrakhan-Guryev strikeslip(?) fault separating structures of the western and eastern 

Caspian Sea (fig. 2).

Proved hydrocarbon reserves of the system exceed 6 billion barrels of oil equivalent (BOE), most of which (84 percent) 

is oil. Most hydrocarbons are in Middle Jurassic clastic reservoirs on the Zhetybay step (structural terrace) south of the 

Mangyshlak foldbelt (fig. 4). Fields in the area include two giant 

(Uzen and Zhetybay) and a number of medium and small fields. 

Several small accumulations have been discovered in carbonate 

and clastic Triassic reservoirs on the Zhetybay step, on the slope 

of the Karabogaz arch, and on the Peschanomys uplift. Despite 

significant exploration efforts, no fields have been found in the 

deep South Mangyshlak (Zhazgurly and Segendyk) depressions. 

Source rocks have not been geochemically identified; however, 

spatial distribution of hydrocarbon accumulations indicates that 

major source rocks occur in the Lower–Middle Triassic section. 

Lower–Middle Jurassic coaly, continental to marine rocks could 

have been a secondary source, but probably of limited importance.

Discovery History

Shallow core drilling for delineation of surface structures 

on the Zhetybay step started in 1957. In 1960, one of the wells 

penetrated a shallow gas pool in Cretaceous rocks of the Uzen 

field. Deep drilling began shortly thereafter, and in 1961 two 

giant fields, Uzen and Zhetybay, in Lower–Middle Jurassic clastic rocks, were discovered. Exploration in the following years 

was targeted at this section, and a series of smaller discoveries 

were made. By the end of the 1960’s, structural prospects of the 

Zhetybay step had been largely exhausted, and attempts to 

explore structures in the South Mangyshlak depressions had 

failed. The first gas and condensate flow from the Triassic section was obtained in 1972 in the South Zhetybay field, opening a 

new play in the petroleum system. Exploration efforts then were 

extended to the Peschanomys uplift and the slope of the 

Karabogaz arch where a number of medium and small size 

fields in Triassic rocks were found. Several wells were also 

drilled offshore, but only noncommercial hydrocarbon flows 

were obtained.

Petroleum Occurrence

Most oil and gas fields of the system and the great majority 

of discovered reserves are found on the Zhetybay step, which is 

a gently southward dipping structural terrace between the Bekebashkuduk anticline of the Mangyshlak foldbelt and the deep 

depressions farther south (fig. 4). Except for a few small gas 

accumulations in Cretaceous rocks of the Uzen field and several 

oil and gas condensate accumulations in Triassic rocks, all pools 

occur in the Lower–Middle Jurassic clastics below the Upper 

Jurassic regional seal. On the Bekebashkuduk anticline, 

deformed Triassic rocks are overlain by a thin Jurassic-Cretaceous section, and the regional seal is truncated by a pre-Cretaceous unconformity. Several heavy oil accumulations, including 

the very large Karasyaz-Taspas pool at depths of 400–500 m, are 

known in Lower Cretaceous rocks. These rocks also contain a 

few pools on the western plunge of the Bekebashkuduk and 

more northern anticlines of the Mangyshlak foldbelt.

Several oil and gas condensate fields of small to medium 

size have been discovered south of the South Mangyshlak 

depressions. The fields are located on the Peschanomys uplift 

and on the northern slope of the Karabogaz arch, above or near 

the Kara-Audan buried rift of Late Permian(?)-Triassic age (fig. 

5; Murzagaliev, 1996). Most reserves of these fields are in the 

Middle Triassic carbonate formation although a few pools are 

present in other parts of the Mesozoic section. A medium-size 

oil pool has been discovered in a fractured granite batholith of 

the basement in the Oymasha field. 

Few wells have been drilled offshore, but all failed to make 

commercial discoveries. Only one well in the Rakushechnayamore prospect on the offshore extension of the Peschanomys 

uplift (fig. 2) recorded a significant gas condensate show from 

Triassic rocks, but apparently the show was considered noncommercial. Despite significant exploration efforts, no discoveries 

have been made in either the Segendyk or Zhazgurly depressions (fig. 4), although structural traps, Lower–Middle Jurassic 

reservoir rocks, and a thick Upper Jurassic seal are present there.

All oils of the petroleum system have common chemical 

characteristics. They are of medium gravity (31°–38° API in 

most pools) and have very high paraffin (to 30 percent) and resin 

(10–20 percent) contents and low sulfur content (0.1–0.25 
8 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

Segendyk

Uplift

Uplifts

I

II

I

II

 N

Depression

Zhetybay

Ste

p

Peschanomys

Zhazgurly

Depressio

n

Kazakh

Depress

oi n

S

o

u

t

h

M

a

n

g

y

s

h l a

k

D

e

pr

e

s

s i o

n

s

Tumgachi Anticline

Kolsay

Depression

Uplift

Karashek

Central Ustyurt

System

of

Muzbel Uplift

Ty

u

b-Karagan

Anticline

K a

r

a

b

o

g

a

z

A

r

c

h

North Ustyurt Basin

B

e ke

b

a s h

k u d

u

k

A

n t i c l i n

e

Karagi

Saddle

Karatau

Anticline

M

a

n

g

y

s

h l a

k

S

y

s t e

m

o

f

U

pl i f t

s

C h a

k

y r g

a

n

T r o

u g

h

C a s p i a n S e a

0 20 40 60 KILOMETERS

Boundary of major tectonic unitBoundary of other structures

Figure 4. Generalized map showing structural units of South Mangyshlak petroleum system (modified from Krylov, 1971). Cross sections are shown in figures 6 and 7.

Line of cross section, figures 6 and 7

EXPLANATION

50° 55° E

percent). No significant changes in chemical properties of oils 

from different depths are noticeable. None of the South Mangyshlak oils have been studied by modern geochemical methods. 

However, group compositions of Jurassic and Triassic oils are 

similar, and both oil groups are highly mature and are characterized by similar distribution of normal alkanes (Timurziev, 

1986). These characteristics and other geologic data suggest that 

the oils were probably generated from the same source rock. 
South Mangyshlak Total Petroleum System (110902), Middle Caspian Basin, Kazakhstan 9

C A S P I A N

S E A

KARABOGAZ

BAY

KARA-AUDAN RIFT

CENTRAL MANGYSHLAK

RIFT

TUARKYR

RIFT

Figure 5. Sketch map showing Triassic rift systems of South Mangyshlak (modified from Murzagaliev, 1996). No scale.

 __ __

EXPLANATION

Outcrop of Triassic-Jurassic rocks

Gravity anomaly

Fault

Inferred fault

N

Gases of the petroleum system are typical thermogenic gases. 

They contain 8–15 percent ethane and heavier homologues, 

small amounts of carbon dioxide (0.4–1.7 percent), and varying 

amounts of nitrogen (1–10 percent).

Stratigraphic Section

The upper Olenekian–Middle Triassic carbonate formation, 

which includes the main source rocks, overlies lower Olenekian 

marine variegated clastics and Induan red beds, which are more 

than 1,500 m thick on the Zhetybay step. These rocks thin and 

pinch out on the Peschanomys uplift. Older, Upper Permian, 

gray clastic rocks are present only in the Mangyshlak and, probably, in the Kara-Audan rifts. Upper Triassic marine clastics, 

directly overlying the upper Olenekian–Middle Triassic carbonate formation, are preserved chiefly in the South Mangyshlak 

depressions where they are up to 600 m thick. On the Zhetybay 

step and slopes of the Karabogaz arch, the rocks were eroded in 

pre-Jurassic time (figs. 6, 7).
10 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 



RIFT Km

KARA-AUDAN

PESCHANOMYS UPLIFT ZHETYBAY S

KARAGI SADDLE

Bekturly Rakushechnaya - more N. Rakushechnaya S. Zhetybay Zhetybay

Basement

Basement

Oil and gas pools

1

203

4

5

6

P2 (?)

K1

J2

K2

J1

J3

SW

I

T1

b.s.l.

Figure 6. Cross section through South Mangyshlak petroleum system (modified from Orudzheva and others, 1985). Location shown in figure 4. Pz, Paleozoic; K, Cretaceous; T, Tertiary. Subscripts 1, 2, and 3 denote lower, middle, and upper, respectively. 

Fault

EXPLANATION

1

1

2

3


South Mangyshlak Total Petroleum System (110902), Middle Caspian Basin, Kazakhstan 11

II 

FaultOil and gas pools

Basement

Kuduk

SLOPE OF KARABOGAZ ARCH

Tamdy Bukbash Temir-Baba Aksu-Kendyrli

ZHAZGURLY DEPRESSION

Kaundy Kurganbay

KARA-AUDAN RIFT

01

2

3

4

Km b.s.l.

Basement

S

Figure 7. Cross section through South Mangyshlak petroleum system (modified from Orudzheva and others, 1985). Location shown in figure 4. P, Permian; 



Cretaceous; T, Tertiary. Subscripts 1, 2, and 3 denote lower, middle, and upper, respectively.

P2

K2

K1

T1

T2

J3

J2 J1

EXPLANATION

1

2

2 2

1

3 
12 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

The Lower–Middle Jurassic (to top of the lower Callovian) 

section includes the principal producing pays of the petroleum 

system. The lower part of the section (through the Bajocian) is 

composed of various coal-bearing continental clastics. Marine 

interbeds are more common in the Bathonian. Thickness of the 

section reaches 1,300–1,400 m in central parts of the South 

Mangyshlak depressions and thins to 800–1,000 m on the Zhetybay step. An overlying marine transgressive section of middle 

Callovian–Kimmeridgian age consists of shales and carbonates 

and is a regional seal. The section is 500–700 m thick in central 

areas of the South Mangyshlak depressions and thins northward 

and southward. The Volgian Stage is absent.

The Lower Cretaceous section is 1,100–1,200 m thick in 

the depressions and 700–900 m thick on the Zhetybay step. The 

section is composed of Valanginian-Hauterivian carbonates, 

Barremian continental clastics, and thick Aptian-Albian marine 

shales with beds of sandstone. The Upper Cretaceous is 300–600 

m thick in the depressions and thins to 100–200 m toward the 

Mangyshlak foldbelt. It includes Cenomanian–lower Turonian 

marine clastics and upper Turonian–Maastrichtian carbonates. 

Paleocene-Eocene rocks are chiefly carbonates, 50–200 m thick, 

unconformably overlying Upper Cretaceous rocks. The Maykop 

series (Oligocene–lower Miocene) is composed of marine shales 

up to 800 m thick in the depressions and 100–200 m thick on the 

Zhetybay step and Peschanomys uplift (figs. 6, 7). Middle 

Miocene and younger rocks lie unconformably on various parts 

of the Maykop series. They are present only in the South 

Mangyshlak depressions and are not more than 250 m thick.

Source Rocks

Source rocks for the petroleum system have not been positively identified. Two opposing points of view suggest that (1) 

source rocks for Triassic-reservoired oils are in the Lower–Middle Triassic marine section, whereas Jurassic and Cretaceous 

oils were generated from largely continental Lower–Middle 

Jurassic rocks with mainly type III kerogen (Kabanova and 

Braslavskaya, 1979; Florensky and others, 1975) and (2) all oils 

were generated from Triassic source rocks and migrated into 

overlying strata (Timurziev, 1986). Although convincing 

geochemical data are absent, geologic considerations suggest 

that the principal source rocks of the petroleum system are stratigraphically confined to the upper Olenekian–Middle Triassic 

section composed of alternating shales, carbonates, and tuffs. 

Thickness of the section is about 750 m in the southern part of 

the Zhetybay step and 250–300 m on the Peschanomys uplift. 

Measured TOC contents in shales reach 9.8 percent and organic 

matter is dominated by type II kerogen (Shablinskaya and others, 1990). An interval of black bituminous shales (“oily shale”) 

is present on the Zhetybay step in the Karadzhatyk Formation of 

the upper Olenekian Stage (Florensky and others, 1975). The 

generative potential of Induan and Upper Triassic rocks is substantially lower (Tverdova and others, 1982; Tverdova, 1988). 

Source rock quality of Lower–Middle Jurassic rocks is poor. 

Kerogen is dominantly of type III, and TOC content in shales 

commonly ranges from 0.5 to 1 percent reaching 1.5 percent 

only in the central part of the Segendyk depression (Polyakova, 

1977).

In central areas of the South Mangyshlak depressions, 

Lower–Middle Jurassic rocks are thicker, buried at greater 

depths, and contain higher TOC. Structural traps, reservoir 

rocks, and seals are present; however, despite a significant 

amount of drilling, no discoveries have been made. Most probably, the lack of discoveries is related to insufficient generative 

potential of these rocks. Probable Triassic source rocks have 

been deposited in different geologic environments. Major areas 

of subsidence and best conditions for source rock deposition 

were confined to grabens of the Mangyshlak and Kara-Audan 

rifts and their shoulders where deeper-water anoxic basins probably existed (fig. 5). In the central zone of the former, Lower–

Middle Triassic source rocks are strongly overmature and were 

deformed during rift inversion and folding. The source rocks 

were truncated by pre-Jurassic erosion in the northern part of 

the Zhetybay step where the giant Uzen field is located. However, Lower Triassic rocks that subcrop at the pre-Jurassic 

unconformity in this area may belong to the upper thrust sheet 

and may be underlain by younger Triassic source rocks. The 

Lower–Middle Triassic source rocks are certainly present in the 

southern part of the Zhetybay step and in the Kara-Audan rift 

(Orudzheva and others, 1985). Areas of the present-day South 

Mangyshlak depressions are between the two rifts and, in Triassic time, probably were a shallow-water platform devoid of 

organic-rich rocks. Another model that seems improbable, but 

cannot be excluded, is that Lower–Middle Triassic source rocks 

do extend from the Zhetybay step into the South Mangyshlak 

depressions, but hydrocarbons could not migrate upward into 

Jurassic reservoirs because of the lack of significant faults and 

the presence of the Upper Triassic seal.

The preceding considerations indicate that the principal 

source rocks of the South Mangyshlak petroleum system are 

basinal facies of parts of the upper Olenekian–Middle Triassic 

carbonate formation, probably its upper Olenekian part 

(Karadzhatyk Formation). The expected main areas of source 

rock development are the southern zone of the Zhetybay step, 

possibly the Bekebashkuduk anticline, and the Kara-Audan rift 

(figs. 4, 5). All discovered fields of the TPS are found either in 

these areas or updip in close proximity to them. The generative 

potential of Lower–Middle Jurassic rocks that contain most of 

petroleum reserves is low. Possibly, these rocks generated some 

gas, which is mixed with hydrocarbons migrated from the principal source.

Time of the beginning of oil generation by Triassic source 

rocks is uncertain. The present-day geothermal gradient varies 

from 38° to 41°C/km in most wells; however, it was probably 

substantially higher during the Triassic rifting event. Following 

this event, large volumes of Triassic rocks were denuded in preJurassic time. A leap in vitrinite reflectance values between 

uppermost Triassic and basal Jurassic rocks has been reported 

in some wells (Bobylev and Grechishnikov, 1983). These uncertainties hamper modeling of oil generation history. Oil generation probably started during deposition of thick Cretaceous 

rocks and continued through deposition of the Oligocene–lower 

Miocene Maykop series (fig. 8). Pre-middle Miocene uplift 

resulted in deep and extensive erosion of older sediments, and 

little or no hydrocarbon generation could have occurred afterwards.
South Mangyshlak Total Petroleum System (110902), Middle Caspian Basin, Kazakhstan 13

Reservoir Rocks

Principal reservoir rocks of the TPS, which contain the 

dominant part of oil and gas reserves, are confined to the Lower–

Middle Jurassic section. They are sandstones interbedded with 

shales and mudstones. Thirteen productive intervals are present. 

Gross thickness of each interval ranges from 35 to 65 m, and net 

thickness ranges from 10 to 30 m. Significant lateral discontinuity and lens-like geometry greatly complicate the production 

(Ulmishek, 1990). The sandstones are fine to medium grained, 

polymictic, commonly poorly rounded, poorly to moderately 

sorted, with argillaceous and calcareous cement. Clay content 

varies widely from several to 40–50 percent, but is commonly 

high. On the Zhetybay step, porosities decrease from 18–23 percent at depths of 1,050–1,300 m (Uzen field) to 14–18 percent at 

depths of 1,950–2,650 m (South Zhetybay field). Permeability is 

highly variable (from several to 1,200 mD) and, unlike porosity, 

depends on clay content. Best reservoir properties are within 

channel sandstones (braided-stream deposits) that are present in 

several reservoirs.

Most hydrocarbons in the Triassic sequence are found in 

Middle Triassic carbonate reservoirs, and noncommercial oil 

flows have been obtained from the other parts of this sequence. 

Reservoir rocks are fractured carbonates with dominant vuggy 

porosity. Best reservoir rocks are in a bed 30–180 m thick (Bed B 

of local nomenclature), consisting of alternating tuffs and leached 

oolitic dolomites with porosities exceeding 20 percent and permeabilities to 200–300 mD (Cherbyanova and others, 1984). Reservoir properties are enhanced by vugs and fractures; matrix 

porosity of dolomites does not exceed 3–4 percent and permeability is near zero. The leaching has developed along neotectonic 

(post-early Miocene) fracture systems (Timurziev, 1984).

A significant oil pool in the Oymasha field is reservoired in 

fractured and weathered basement granites directly overlain by 

Triassic carbonates. Productivity of the granites extends 300 m 

below the basement surface. Data on reservoir properties are not 

available, but oil flow rates ranged from several to as much as 

more than 2,000 b/d (barrels per day) during well tests.

Several hydrocarbon pools have been discovered in Cretaceous rocks in areas where the Upper Jurassic seal is eroded 

(western plunge of the Mangyshlak foldbelt). Most hydrocarbons are reservoired in Aptian and Albian marine sandstones 

that have porosities of 16–21 percent and permeabilities of a few 

tens of millidarcies.

Seal Rocks

Only one regional seal of high quality that is present in the 

stratigraphic section consists of Upper Jurassic (upper Callovian–Kimmeridgian) transgressive marine shale and carbonate 

beds. Carbonates become more common and compose a large 

part of the seal in the southern areas of the TPS. The regional 

seal controls the principal oil and gas reserves in Lower–Middle 

Jurassic rocks, although separate pools may be directly capped 

by shale and mudstone beds alternating with reservoir sandstones. The Upper Jurassic seal is more than 500 m thick in 

deepest parts of the South Mangyshlak depressions but thins to 

100–300 m on the Zhetybay step. The seal is highly effective; it 

is less than 100 m thick in the Uzen field, but nevertheless traps 

a giant oil accumulation with the oil column more than 300 m 

high.

The Triassic sequence does not contain regional seals. 

Hydrocarbon accumulations in this sequence are apparently 

sealed by dense carbonates and tuffs that have not developed 

secondary porosity and permeability.

Traps

Almost all hydrocarbon reserves in the principal producing 

Lower–Middle Jurassic section are in structural traps of the 

Zhetybay step. These traps are elongated anticlines grouped in 

three lines approximately parallel to the Mangyshlak foldbelt. 

Length of the anticlines varies from a few to 45 km (Uzen field), 

and closures range from a few tens to more than 300 m. Dips on 

the southern flanks of the anticlines substantially exceed those 

on the northern flanks, and the southern flanks are commonly 

faulted. The morphology of the anticlinal traps indicates that 

they were formed by compression in the direction normal to the 

Mangyshlak foldbelt. Interpretation of seismic data suggests that 

Jurassic-Tertiary anticlines are underlain by leading edges of 

thrust sheets in Triassic rocks (Popkov, 1991). Southward thrusts 

in Triassic rocks have been mapped in the Mangyshlak foldbelt, 

and thrusting evidently extends across the entire Zhetybay step.

Although principal thrusting of Triassic rocks took place in 

pre-Jurassic time, some compression and movements along 

thrust planes continued during late Mesozoic and Tertiary time. 

The movements occurred mainly during regional uplifts in preCretaceous, pre-Tertiary, and post-early Miocene times (Popkov, 

1991). The latest period was most important; about 70 percent of 

structural growth took place between the middle Miocene and 

the present (fig. 8).

Known stratigraphic traps in Jurassic rocks are few. Only 

one small oil accumulation in the Burmasha field has been found 

in Middle Jurassic fluvial channel sandstone, but no exploration 

was specifically targeted at stratigraphic traps. Because of significant lateral discontinuity of Jurassic lithologies in alluvial 

and nearshore depositional environments, potential for stratigraphic traps is probably high (Dmitriev and others, 1982).

Oil and gas accumulations in Triassic and basement rocks 

of the Peschanomys uplift and northern slope of the Karabogaz 

arch are in traps different from those of the Zhetybay step. 

Although exploration was targeted at structural uplifts, hydrocarbon accumulations are actually controlled by zones of fracturing and related leaching of carbonates (Makhutov, 1989). The 

zones have northeastern and northwestern trends. The northeastern zones are connected with faults having a significant strikeslip component, and the northwestern zones are interpreted as 

tear fractures (Timurziev, 1986). Both systems of fractures were 

formed in post-early Miocene time (Larichev, 1988).

Preceding data suggest that oil and gas fields of the South 

Mangyshlak TPS were mainly, and perhaps exclusively, formed 

in the post-early Miocene (neotectonic) stage of development. 

Generation of hydrocarbons during this stage did not take place. 

Thin (maximum 250 m) sediments were deposited only in central areas of the Segendyk and Zhazgurly depressions where the 
14 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

248

144

 65

 24

206

200

250

150

100

50

Permian

Triassic

Jurassic

Cretaceous

Paleogene

Neogene

Plio

Mio

Olig

Eoc

Pal

0 GEOLOGIC

TIME SCALE

 PETROLEUMSYSTEM EVENTS

ROCK UNITSOURCE ROCK

RESERVOIR ROCK

SEAL ROCKOVERBURDEN ROCK

TRAP FORMATION

HC GENERATION

ACCUMULATION

PRESERVATION

CRITICAL MOMENT

L

E

L

M

E

L

L

E

M

E

?

Basement

Figure 8. South Mangyshlak petroleum system events chart. Question marks indicate uncertainty.

?
Terek-Caspian Total Petroleum System (110901), Middle Caspian Basin, Russia 15

principal Triassic source rocks are probably absent. Productive 

areas of the system and Triassic rifts that contain source rocks 

experienced uplift and erosion during this stage. Migration of oil 

and gas into traps postdated maturation and hydrocarbon generation (fig. 8). The inception of migration was probably caused by 

faulting and fracturing of overpressured mature source rocks and 

overlying beds, which created migration paths.

Assessment Units

Assessment Unit 11090201, South Mangyshlak (Entire) 

In this report, the South Mangyshlak TPS is considered a 

single assessment unit although parts of the system have different potential. Assessed undiscovered oil and gas resources of the 

TPS are shown in table 1. Complete statistical data on the 

assessment of this and other units can be found in U.S. Geological Survey World Energy Assessment Team (2000). Offshore 

area of the western plunge of the Mangyshlak foldbelt and Bekebashkuduk anticline (fig. 4) possesses the best potential. Triassic 

source rocks responsible for large hydrocarbon reserves of the 

Zhetybay step extend into the area. The intensity of folding 

decreases westward, and seismic surveys indicate the presence 

of structural traps (Lebedev and others, 1987). Good preservation conditions can be expected because of increasing depths to 

potential targets. Large oil and gas condensate pools may be primarily reservoired in Jurassic and Cretaceous rocks. The Zhetybay step itself is maturely explored and has limited future 

potential for small fields in Triassic structural traps and in Jurassic stratigraphic traps.

No oil or gas has been found in the South Mangyshlak 

depressions, probably because of the absence of Triassic source 

rocks and the low efficiency of possible Jurassic source rocks. 

Even if Triassic source rocks extend from the Zhetybay step into 

the depression under the Upper Triassic seal, only small pools at 

great depths (greater than 4–5 km) can be expected. The potential of this structure and its offshore continuation is low.

The productivity of the Peschanomys uplift and the northern slope of the Karabogaz arch is related to Triassic source 

rocks of the Kara-Audan rift (fig. 5). Unlike on the Zhetybay 

step, hydrocarbons are contained only in Triassic fractured reservoirs of inferior quality, and drilled wells indicate no signs of 

migration into overlying Jurassic sandstones. Only structural 

prospects have been drilled. However, reservoirs in zones of 

fracturing are probably present outside local uplifts, and many 

small to medium-size fields may be found. Regional updip 

pinch-out zones of Mesozoic rocks on the slope of the 

Karabogaz arch are potential for discoveries in stratigraphic 

traps. The offshore continuation of the Peschanomys uplift also 

has significant potential, although a few drilled structural prospects there have not been commercial discoveries. Productivity 

of Jurassic rocks in this part of the system depends on the presence of migration paths between Triassic source rocks and Jurassic reservoirs and, although not proven, is possible, especially in 

the offshore area.

In the Kazakh depression (figs. 2, 4), potential Jurassic and 

Triassic targets occur at depths of 3–4 km and more. Triassic 

source rocks are probably absent. No significant structural prospects have been identified (Lebedev and others, 1987), and no 

wells have been drilled. Petroleum potential of the depression is 

probably low. 

Terek-Caspian Total Petroleum System (110901), 

Middle Caspian Basin, Russia

Introduction

The Terek-Caspian total petroleum system (TPS) lies in the 

eastern North Caucasus region and occupies the foredeep of the 

same name (figs. 1, 2). On the south, the system is bounded by 

the Great Caucasus foldbelt. The boundary with the StavropolPrikumsk TPS to the north is along the Nogay monocline, which 

is the northernmost structural unit of the foredeep (fig. 9). To the 

west, the TPS terminates along the slopes of the Mineralovod 

high and Stavropol arch, an uplifted structural trend transverse to 

the Caucasus strike that separates the eastern and western 

branches of the North Caucasus foredeep troughs. On the southeast, the system extends into the poorly known North Apsheron 

depression offshore in the Caspian Sea (fig. 2).

Original oil reserves of the TPS amount to 3.4 billion barrels whereas non-associated gas reserves are small (0.2 TCF). 

Almost all fields are controlled by structural traps related to 

thrusting of the Great Caucasus foldbelt onto the MesozoicCenozoic epi-Hercynian platform. Oil and gas pools occur in 

reservoirs ranging in age from Late Jurassic to Miocene. Most 

original reserves (55 percent) are in Upper Cretaceous fractured limestone reservoirs of the Terek-Sunzha zone (fig. 9), 

but substantial reserves (30 percent) are also in middle 

Miocene sandstones. Reserves in Upper Jurassic and Lower 

Cretaceous carbonate and sandstone reservoirs are much 

smaller. The most important source rocks are probably shales 

of the Oligocene–lower Miocene Maykop series, but some 

endowment of hydrocarbons from older potential source rocks 

in the upper Eocene, Upper Jurassic, and Lower–Middle Jurassic sections is possible.

Discovery History

Surface oil seeps in the Terek-Sunzha anticlinal zone near 

Groznyi (fig. 9) have been known for a long time, and oil was 

produced there from hand-dug wells starting in the early 1800’s. 

The first producing well was drilled into middle Miocene sandstones of the Starogroznen field in 1893 by an Englishman, 

Alfred Stuart. The Berekey field in the South Dagestan area 

(western zone of the South Dagestan projection in fig. 9) was 

discovered in 1899. Oil production increased rapidly and 

reached a total of 8.8 million barrels by 1910.

After revolution in Russia, exploration resumed in the 

1930’s, and several significant fields were discovered in shallow 

middle Miocene sandstones. However, major discoveries were 

made after World War II, in the 1950’s, when a number of large 

and highly productive pools were found in Upper Cretaceous 

rocks. Maximum production was reached in 1970–1971, after 

which production started to decline, as new discoveries were 

much smaller.
16 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

Figure 9. Structural map of eastern North Caucasus region (modified from Sokolov and others, 1990). Dot pattern, Terek-Caspian foredeep;

dot-circle pattern, deepest depressions of the foredeep (outlines hachured to indicate closed low). Arrows in Groznyi area show Terek and 

Sunzha anticlines. Lines I-I, II-II, and III-III are approximate locations of cross sections in figures 10 and 16. Kochubey 2 and 

Gorokhov 9 are locations of wells in figures 17 and 18. 

 

MINERALOVOD

 HIGH

STAVROPOL

 ARCH

NORTH CASPIAN

 BASIN KARPINSKY

RIDGE

EAST MANYCH TROUGH

+ Gorokhov 9

PRIKUM SK U PLIFT

Caspian

Sea

III

III

+ Kochubey 2

N O G A Y M O N O C L I N E

I

I

II

II

.

Groznyi

G R E A T C A U C A S U S F O L D B E L T

DAGESTAN

PROJECTION

Makhachkala

0 100 KILOMETERS

 N

Scale approximate

EXPLANATION

Fault—Arrow shows relative

 horizontal displacement

Budennovsk

Petroleum Occurrence

The largest fields of the petroleum system and the main 

hydrocarbon reserves are concentrated in the Terek-Sunzha anticlinal zone (figs. 9, 10A). The zone consists of two principal 

anticlines (Terek and Sunzha anticlines) and two subordinate 

deeper lines of folds. The anticlines are related to thrust sheets 

with decollement along Tithonian (Upper Jurassic) salt (fig. 

10A). Largest and most productive pools are in the Upper Cretaceous–Eocene fractured carbonate formation at depths of 1,650–

5,200 m (fig. 11). Also large, but presently substantially depleted 

reserves are present in middle Miocene sandstones at shallow 

depths. Smaller pools have been discovered in Lower Cretaceous sandstone and carbonate and in Tithonian suprasalt carbonate reservoirs. Most reserves are oil, but several gas 

condensate pools are also present.
Terek-Caspian Total Petroleum System (110901), Middle Caspian Basin, Russia 17

AB

Paleozoic-TriassicLower–Middle Jurassic

Upper Jurassic

–Eocene

Upper Jurassic salt

Maykop SeriesMiddle

–Upper Miocene

Figure 10. Cross sections through Terek-Sunzha (

A) and Dagestan (

B) thrust belts (modified from Sobornov, 1995). Wedge-shaped frontal parts of thru

salt (

A) and Maykop plastic shales (

A & 

B). Location of cross sections shown in figure 9.

TEREK-CASPIAN FOR

Sunzha Anticline Terek 

NORTH CAUCASUS

Chernogor Monocline

S

I 

2

05

10

Km

DAGESTAN THRUST BELT

II S

STRATIGRAPHIC SEQUENCES

0

5

10

Km 0
18 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

South of the Terek-Sunzha zone, two small fields (Datykh 

and Benoy) have been discovered in thrust-related folds of the 

Caucasus foothills. Farther east and southeast, several oil and 

gas fields are found in the continuation of the thrust system 

where most reserves are also in Upper Cretaceous carbonate and 

Miocene sandstone reservoirs. Only one prospect has been 

drilled in the offshore portion of the thrust belt, and a gas condensate flow was obtained from middle Miocene sandstones of 

the Inchkhe-more field.

North of the North Caucasus thrust system, a few noncommercial discoveries have been made on the Nogay monocline 

(fig. 9). Oil and gas were tested from Cretaceous rocks, largely 

from Upper Cretaceous carbonates. The traps are platform-type 

basement-related anticlinal uplifts different from traps of the 

thrust belt. In the absence of geochemical data, it is uncertain 

whether these fields constitute a part of the Terek-Caspian TPS, 

as inferred in this report, or whether they should be attributed to 

the Stavropol-Prikumsk TPS to the north.

Oils in Cretaceous and Mesozoic reservoirs are of low viscosity and gravity (mostly 37°–41° API). They have low sulfur 

and resin contents and a moderately high (5–10 percent) content 

of solid paraffin. GOR is typically high, varying in most pools 

from 1,400 to 2,600 ft3

/bbl. Pools in Miocene rocks are largely 

less than 1,200 m deep and contain heavy, biodegraded oils with 

high (to 25 percent) resins content and low paraffin and sulfur 

contents. The oils are significantly devoid of paraffinic hydrocarbons and largely consist of naphthenes and aromatics. Limited 

geochemical chromatography data suggest similarity of Miocene 

oils of the Terek-Sunzha zone to Mesozoic and Miocene oils of 

the Dagestan thrust belt (Sokolov and others, 1990). Data indicate that the oils were sourced from low to moderately mature 

source rock, probably from Maykop series shales. The data are 

inadequate to determine the affinity of Mesozoic oils of the 

Terek-Sunzha zone to the same group.

Stratigraphic Section

The basement of the Middle Caspian basin is a Hercynian 

accreted terrane, which includes several microcontinents. One of 

them, the North Caucasus microcontinent, crops out in the northern range of the foldbelt. The Paleozoic sedimentary cover of the 

microcontinent extends into the western area of the Terek-Caspian TPS, but its dimension is unknown. Triassic rocks, which 

fill rifts to the north of the area, may be present in the foredeep at 

great depths.

Basement or Triassic rocks are overlain by a thick Lower–

Middle Jurassic clastic formation (fig. 11). North of the Caucasus Range, most of the formation is composed of BajocianBathonian marine shales up to 2 km thick that include some 

sandstone beds. Thickness decreases northward, and the formation pinches out on slopes of the Stavropol arch. Upper JurassicNeocomian rocks unconformably overlie the Middle Jurassic. 

The rocks were deposited in arid climatic conditions. The section consists of carbonates and includes thick (to 1,000 m) lower 

Tithonian salt in the western half of the TPS area. Thick Oxfordian-Tithonian reefs are exposed in the northern zone of the Caucasus, along the southern margin of the salt basin. To the north 

and west, the salt grades into red continental clastics. The 

Aptian-Albian section is 500–700 m thick and is composed of 

marine shales with beds of glauconitic sandstones. Upper Cretaceous rocks are carbonates and marlstones 300–600 m thick. 

Thickness increases to 1,400 m in a local depocenter just northwestward of the Dagestan projection (Bayrak, 1982). PaleoceneEocene rocks are carbonates and marls of a condensed section 

only 50–100 m thick. The rocks were deposited in deep-water 

conditions; by the end of the Eocene the water depth could have 

exceeded 1,000 m (Berlin and Ulmishek, 1978). 

The Upper Cretaceous–Eocene carbonate formation is 

overlain by the Maykop series of Oligocene–early Miocene age. 

In the TPS area, the series almost exclusively consists of shales 

and is up to 1,600 m thick. Shales in the lower part of the series 

were deposited in a deep-water basin inherited from Eocene 

time. The basin became progressively shallower by the end of 

Maykop deposition. The shales are undercompacted and overpressured, and experienced plastic flow in zones of tectonic 

stress. The principal provenance areas were to the northeast; 

however, large olistostromes, which include huge blocks of 

underlying carbonates, reaching a cubic kilometer in volume, are 

present along the Caucasus and indicate the beginning of orogenic uplift.

The middle Miocene through Quaternary sequence consists 

of coarsening-upward clastic rocks, which include some upper 

Miocene carbonate beds. This orogenic sequence fills a foredeep 

formed along the Caucasus front. Thickness of the rocks in the 

foredeep axial zone can exceed 5 km. To the north, the sequence 

rapidly thins onto the foreland slope.

Jurassic through Eocene rocks of the Terek-Caspian TPS 

were deposited on the southern continental margin of Eurasia. 

Sedimentation was characterized by a passive-margin regime 

because the TPS area was separated from the active Tethyan 

margin by the Transcaucasus microcontinent and the marginal 

sea of Great Caucasus. Provenance for clastic material was far to 

the north, on the Russian craton. First signs of Caucasus orogenic uplift appeared in Oligocene time and progressively 

increased afterwards. However, not until late Miocene-Pliocene 

time did the orogen became the dominant source of clastic material and the present-day foredeep come into existence.

Source Rocks

Geologic and limited geochemical data indicate that the 

most important source rocks of the Terek-Caspian TPS occur 

within the thick Maykop series (Oligocene–lower Miocene). The 

lower part of the series was deposited in a deep anoxic marine 

basin, which was gradually filled with clastic sediments of the 

upper part of the series (Ulmishek and Harrison, 1981). Lower 

Maykop shales and marlstones are characterized by variable, but 

commonly high (to 4.4 percent) TOC content and dominant type 

II kerogen. Hydrogen index in the lower to middle part of the oil 

window reaches 250–260 mg HC/g TOC. Toward the top of the 

Maykop series, TOC decreases to 1–2 percent, and organic matter contains much more terrigenous constituents. In the depressions of the foredeep, the lower Maykop series occurs in the 

lower part of the oil window and into the gas window (fig. 12D).
Terek-Caspian Total Petroleum System (110901), Middle Caspian Basin, Russia 19 Figure 11. Columnar stratigraphic section of Mesozoic-Tertiary rocks of Terek-Caspian petroleum system (modified from Ulmishek and Harrison, 1981). 

Oxfordian

Kimmeridgian

TithonianAalenian

Bajocian

Bathonian

Callovian

Neocomian

Barremian

Aptian

Albian

Cenomanian

Turonian

Coniacian

Santonian

Maastrichtian

to 2000 to 1500 100-

1000 500-900

Cretaceous

250 400-550 300-600

Jurassic

Lower Lower Middle Upper Upper

Upper

UpperUpper

Lower

Lower

Lower

Middle

Middle

Middle

Maykop series

Paleogene Neogene

Paleocene Eocene Oligocene Miocene Pliocene Karagan Chokrak Khadum Kuma

<50 50 1200-1500 1200 1300 60-

100

100-

300

1000-

1500
20 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union Makhachkala 1.5 1.2

1.2

1.0

0.5

0.2

1.2

2.0

0.5

1.5

1.0

1.5

1.5

2.0

Groznyi

Groznyi

1.0

0.5

1.0

0.5

1.0

0.5

Makhachkala

Groznyi

Caspian

Sea

Caspian

Sea

Caspian

Sea

Caspian

Sea

1.0

2.0

. . .

.

.

0

0

3.0

2.0

1.0

2.0

1.0 1.0

Makhachkala

2.0

1.0

1.0

1.0

2.0

1.0

0

0.5

1.0

2.0

Groznyi

4.0

4.0

3.0

8.0

8.0

6.0

1.0

5.0

.

4

3

.0

.0

2.0

1.0

2.0

Figure 12. Maturity zones in stratigraphic units of eastern North Caucasus region: A, in Triassic rocks; 

B, in Middle Jurassic rocks; 

C, in Aptian-Albian rocks; 

D, in upper part of Maykop series (modified from Sokolov and others, 1990). Mature source rocks at 

bottom of Maykop series occupy significantly larger area.

.

AB

CD

2.0

. Makhachkala
Terek-Caspian Total Petroleum System (110901), Middle Caspian Basin, Russia 21

?

?

?

?

ROCK UNIT

SOURCE ROCK

RESERVOIR ROCK

SEAL ROCK

OVERBURDEN ROCK

TRAP FORMATION

GENERATIONPRESERVATION

CRITICAL MOMENT

PETROLEUM

SYSTEM EVENTS

GEOLOGIC TIME

SCALE

ACCUMULATION MIGRATION0

100

200

50

150

250

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65

144

206

248 E

E

E

E

M

M

L

L

L

L

Neogene

24

Pal

Eoc

Olig

Mio

Plio

Figure 13. Terek-Caspian petroleum system events chart. Question marks indicate uncertainty.
22 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

Information on the presence of older source rocks in the 

TPS is uncertain because of limited geochemical data. Probable 

source rocks are argillaceous bituminous limestones of the upper 

Eocene Kuma Formation (fig. 11), which is 20–30 m thick and is 

separated from the base of the Maykop series by a 20-m bed of 

light foraminiferal limestone. TOC in rocks of the Kuma Formation averages 2–2.5 percent. The formation was deposited in 

conditions similar to that of the Maykop series, but with lower 

input of clastic material (Berlin and Ulmishek, 1978).

North of the Caucasus Range, Middle Jurassic marine rocks 

include shale beds in which TOC averages 1.15 percent and 

reaches as much as 5–10 percent. Terrigenous organic matter 

dominates. The rocks are in the gas window over most of the 

area (fig. 12B) and could be a gas source for the petroleum system. Source rocks may also be present in the subsalt Upper 

Jurassic section. Rocks of this section have been erratically sampled only in a few wells drilled below the salt on the basin margins, but the presence of source rocks may be inferred by 

analogy with the stratigraphically similar Amu-Darya basin. In 

both basins, salt was deposited in deep lagoons separated by 

reefs from the Tethyan ocean. Significant oil shows from subsalt 

carbonates in the marginal areas of the salt basin (Kosarev, 1982) 

and a gas flow of 9 MMCFD in the Datykh field support this 

supposition.

Although hydrocarbon generation from Jurassic source 

rocks could have started in Cretaceous time, generated hydrocarbons were probably lost because of the absence of traps. The 

principal stage of maturation of younger source rocks took place 

after deposition of the Maykop series, during middle Miocene 

through Quaternary time, contemporaneously with thrusting and 

formation of traps (fig. 13).

Reservoir Rocks

Most oil and gas reserves of the TPS are in Upper Cretaceous–Eocene carbonate reservoirs. Matrix porosity of Upper 

Cretaceous carbonates is low and commonly varies from a few 

to 10 percent; it is even lower in Paleocene-Eocene marlstones. 

Matrix permeability is negligible. Reservoir properties are 

enhanced by the presence of fractures and related vugs. Fracturing resulted from tectonic stress in thrust-related anticlines. 

Most pools are overpressured, and characteristic initial oil flow 

rates are in thousands of barrels per day.

The second important group of reservoirs is confined to 

sandstone beds of the middle Miocene Karagan and Chokrak 

Horizons (fig. 11). Seventeen to twenty-three sandstone beds 

occur much shallower than the Upper Cretaceous and possess 

excellent reservoir properties, although separate sandstone beds 

are laterally discontinuous and commonly pinch out. Thickness 

of each sandstone bed is usually less than 10 m. Lateral discontinuity and significant faulting result in a large number of hydrodynamically isolated pools in many fields (for example, 65 pools 

in the Malgobek-Gorskaya field). Sandstone porosity varies 

from 15 to more than 30 percent, and permeability is commonly 

measured in hundreds of millidarcies. 

Aptian-Albian sandstones and Neocomian and Upper 

Jurassic carbonates contain only a few petroleum accumulations. 

Reservoir properties of both sandstones and carbonates at great 

depths are poor and mainly depend on fracturing.

Seal Rocks

The principal regional seal that controls hydrocarbon accumulations in the Mesozoic sequence is Maykop series shales. 

The shales are undercompacted and overpressured and are characterized by high plasticity in the subsurface. The series is from 

750 to nearly 1,600 m thick and overlies most of the TPS area 

except for the Great Caucasus foothills, where it has been 

eroded. The seal directly overlies the principal reservoirs in the 

Upper Cretaceous–Eocene carbonate formation. Seals for pools 

in underlying Lower Cretaceous and Upper Jurassic rocks are 

dense shales and carbonates that probably would not be effective 

in the absence of Maykop shales. 

Hydrocarbon accumulations in middle Miocene sandstones 

are sealed by alternating shale beds that range up to several tens 

of meters thick. In most uplifted anticlines, upper sandstone 

beds are exposed and either flushed by water or leak oil to the 

surface. An additional high-quality seal of potential importance 

is the Upper Jurassic (Tithonian) salt formation that is only 

locally deformed and is present west and northwest of the Dagestan projection. A number of shows and a gas flow have been 

obtained from subsalt Jurassic carbonates, but this play remains 

unexplored. Because of the presence of a perfect salt seal above 

these shows, they may represent a separate petroleum system 

charged by Upper Jurassic and (or) Lower–Middle Jurassic 

source rocks.

Traps

Structural traps control all oil and gas fields of the TPS, 

although many particular pools are outlined by pinchouts of 

middle Miocene sandstones and by limits of fracturing in Upper 

Cretaceous–Eocene carbonates. Almost all discovered reserves 

are in anticlines related to leading edges of thrust sheets (fig. 

10A), and only a few apparently noncommercial fields are 

known on the Nogay monocline in structural uplifts of the platform type. In the Terek-Sunzha zone, where the principal 

reserves of the petroleum system are concentrated, most discovered fields are in traps which form two east-to-west anticlinal 

lines, the Sunzha anticline on the south and the Terek anticline 

on the north (fig. 10A). The anticlines are expressed on the surface as two ridges. Deformation of Quaternary sediments and 

present-day seismicity indicate their continuing growth. Two 

less pronounced and much deeper structural lines containing 

several smaller fields are present to the north and south. The 

main detachment surface probably is in the Upper Jurassic salt 

formation. The salt itself is deformed by plastic flow and composes cores of the anticlines. It is interpreted from seismic data 

that thrust sheets of competent rocks intruded like wedges into 

undercompacted, plastic Maykop series shales. This intrusion 

caused antithetic reverse faults and thrusts of southern vergence 

to form in the upper part of the sedimentary section (Sobornov, 

1995). Plastic deformation of Maykop shales resulted in 
Terek-Caspian Total Petroleum System (110901), Middle Caspian Basin, Russia 23

additional faulting and folding of post-Maykop rocks, and the 

structure of the latter is substantially different from that of Upper 

Cretaceous rocks. Traps of the main structural lines are long and 

narrow anticlinal folds with closures reaching 1,500 m on Upper 

Cretaceous rocks.

Traps on the northeastern periphery of the Dagestan projection are also thrust-related anticlines that are arranged in three 

structural lines. Progressively younger rocks crop out on consecutively northeastward anticlinal lines. The easternmost line is 

located offshore where only one prospect has been drilled. In this 

part of the TPS area, Jurassic salt is absent, and the main detachment occurs in Lower–Middle Jurassic shales (fig. 10B). In other 

respects, these traps are similar to traps of the Terek-Sunzha 

zone, although the regional structure of the Dagestan zone is 

characterized by more intense deformation.

Assessment Units

Three assessment units are identified in the Terek-Caspian 

TPS (fig. 1). Assessed undiscovered oil and gas resources of 

these units are listed in table 1.

Assessment Unit 11090101, Foldbelt-Foothills 

This unit occupies the front thrust system of the Caucasus 

foldbelt (fig. 1). Almost all discovered hydrocarbon reserves 

belong to this unit. Principal characteristics of undiscovered 

fields are probably similar to that of known fields. Along the 

foldbelt, the prospective area is limited by truncation of the Maykop series seal. Presently, the Terek-Sunzha zone contains the 

dominant reserves of the assessment unit. However, productive 

suprasalt Upper Jurassic through Tertiary rocks of this zone are 

substantially explored to depths of 5–5.5 km, and only smaller 

fields in deep satellite structures can be found. The deeper subsalt Jurassic section occurs below the main detachment surface. 

Probably, it has different structural characteristics and is therefore placed in a separate assessment unit (11090102, Terek-Sunzha Subsalt Jurassic). The area between the Terek-Sunzha zone 

and exposed Caucasus folds is only sparsely explored. However, 

Cretaceous and younger rocks of this area are almost undeformed, and structural prospects have been identified only in its 

southern part (Chernogor monocline; fig. 10A) where two discoveries have been made. Potential of the area is modest at best.

To the east of the Terek-Sunzha zone, the thrust belt is 

sparsely explored north of the Dagestan projection. Deformation 

is complex there (fig. 10B), and both leading edges and rear parts 

of the thrust sheets contain structural prospects. Until recently 

the quality of seismic data was inadequate for prospect mapping. 

The potential of the area is good. Light oil and gas condensate 

fields in both Cretaceous and middle Miocene reservoirs can be 

expected.

Farther to the southeast, the onshore area has been thoroughly explored because structures are expressed in the surface 

geology. Two onshore anticlinal lines have been densely drilled. 

The anticlines are strongly faulted, and the sealing conditions are 

poor. Therefore, the fields are relatively small. The third, less 

deformed anticlinal line has been mapped offshore. One of the 

anticlinal folds, the Inchkhe-more prospect, was drilled, and a 

gas condensate and oil discovery of medium size was made in 

middle Miocene rocks. The field has not been developed, probably because of relatively deep water. The potential of the offshore area is high, and large to medium-size light oil and gas 

fields with high condensate content can be expected.

Assessment Unit 11090103, Foreland Slope and Foredeep 

This assessment unit covers the central, deepest part of the 

foredeep (except for the Terek-Sunzha zone) and the adjacent 

foreland slope north and northeast of the thrust belt (fig. 1). The 

area is virtually unexplored. Only a limited number of wells 

have been drilled with a few small discoveries in the western 

part of the unit. In the foredeep, depths to the potential targets 

are great and exceed 6 to 7 km in the deepest nearshore area and 

in the North Apsheron depression. Depths on the foreland slope 

are shallower, but the slope is significantly undeformed and 

large structural prospects have not been identified. Smaller, lowamplitude anticlinal structures are open to the north and northeast because of the regional dip of rocks toward the foredeep. 

The Tertiary section abruptly thins across the slope. Therefore, 

stratigraphic traps in the middle Miocene and possibly the lower 

part of upper Miocene rocks are likely to be present, but exploration for these traps in a frontier area at great depths is highly 

risky. Younger and shallower rocks are dominantly orogenic 

coarse clastics devoid of seals. The potential of the assessment 

unit is low.

Assessment Unit 11090102, Terek-Sunzha Subsalt Jurassic

 This third assessment unit of the petroleum system 

includes subsalt Jurassic rocks of the Terek-Sunzha zone and 

surrounding areas (fig. 1). The area of the unit is defined by the 

pinchout boundary of the salt. Several attempts to drill into subsalt rocks on structures of the Terek-Sunzha zone, where these 

rocks occur at depths of about 6 km, did not succeed because of 

technical difficulties. The rocks have been penetrated in marginal areas of the salt basin. Shows were recorded and a gas flow 

was obtained from Oxfordian-Kimmeridgian carbonates in the 

Datykh field, which proves the presence of source rocks. The 

salt provides an excellent seal. Structure of subsalt rocks is 

poorly known, but some deformation related to stress from the 

Caucasus is probable. Reef buildups may be present on margins 

of the salt basin. High productivity of Jurassic subsalt carbonates is known in the tectonically and stratigraphically similar 

Amu-Darya basin east of the Caspian Sea where large oil and 

gas reserves have been found in structural traps and Oxfordian 

reefs. Productivity of Upper Jurassic subsalt carbonates and 

underlying Middle Jurassic clastics has been established in the 

East Kuban depression, which is located just west of the Mineralovod high (fig. 9), in the Azov-Kuban basin. Potential of the 

assessment unit may be significant. Sour gas with a high condensate content and light oil in shallower peripheral areas of the 

unit are the most likely hydrocarbons. Potential of the unit is 

assessed based on analogy with the Amu-Darya basin.
24 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

Undiscovered Resources

MFS Prob. Oil (MMBO)

(0-1) F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Total: Assessed onshore portions of Middle Caspian Basin Province

1,005 2,053 3,677 2,159 2,020 5,129 10,273 5,503 117 299 606 322

4,646 19,192 33,101 19,139 121 858 1,569 855

1.00 1,005 2,053 3,677 2,159 6,666 24,321 43,374 24,641 238 1,158 2,175 1,177

Total: Assessed offshore portions of Middle Caspian Basin Province

822 2,683 4,793 2,728 1,689 5,527 10,726 5,766 95 320 625 334

1,457 9,552 17,811 9,278 38 149 318 158

1.00 822 2,683 4,793 2,728 3,146 15,079 28,537 15,044 133 469 943 492

Grand Total: Assessed portions of Middle Caspian Basin Province

1,828 4,737 8,470 4,887 3,708 10,656 20,999 11,269 212 619 1,231 656

6,103 28,744 50,913 28,417 159 1,007 1,887 1,014

1.00 1,828 4,737 8,470 4,887 9,812 39,400 71,911 39,685 371 1,626 3,118 1,670

1.00

1.00

1.00

. . 

Gas (BCFG) NGL (MMBNGL)

Table 1. Middle Caspian basin, Province 1109—Assessment results summary—allocated resources.

[MMBO, million barrels of oil. BCFG, billion cubic feet of gas. MMBNGL, million barrels of naural gas liquids. MFS,

minimum field size assessed (MMBO) or BCFG). Prob., probability (including both geologic and accessibility probabilities)

 of at least one field equal to or greater than the MFS. Results shown are fully risked estimates. For gas fields, all liquids are

included under the NGL (natural gas liquids) category. F95 represents a 95 percent change of at least the amount tabulated. 

Other fractiles are defined similarly. Fractiles are additive under the assumption of perfect positive correlation. Shading indicates 

not applicable]

Undiscovered Resources

MFS Prob. Oil (MMBO)

(0-1) F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Terek-Caspian Total Petroleum System

7 556 1,012 1,728 1,060 1,359 2,555 4,560 2,707 80 153 277 162

42 3,775 7,048 11,874 7,329 107 209 370 220

1.00 556 1,012 1,728 1,060 5,134 9,603 16,435 10,036 188 362 647 382

7 543 988 1,687 1,034 1,327 2,495 4,452 2,643 79 149 270 159

42 944 1,762 2,969 1,832 27 52 93 55

1.00 543 988 1,687 1,034 2,271 4,257 7,421 4,475 105 201 363 214

20 0 264 633 283 0 1,291 3,270 1,413 0 77 198 85

120 0 10,488 18,245 10,051 0 620 1,139 603

0.85 0 264 633 283 0 11,779 21,516 11,464 0 697 1,337 688

7 142 254 445 269 201 377 693 403 12 23 42 24

42 295 623 1,201 670 6 13 26 14

1.00 142 254 445 269 496 1,000 1,894 1,073 18 35 68 38

Gas (BCFG) NGL (MMBNGL)

Foldbelt-Foothills Assessment Unit (50.6% of undiscovered oil fields and 80% of undiscovered gas fields allocated to 

ONSHORE province 1109)

Foldbelt-Foothills Assessment Unit (49.4% of undiscovered oil fields and 20% of undiscovered gas fields allocated to

OFFSHORE province 1109) 

Terek-Sunzha Subsalt Jurassic Assessment Unit (100% of undiscovered oil fields and 100% of undiscovered gas fields 

allocated to ONSHORE province) 

Foreland Slope and Foredeep Assessment Unit (59.5% of undiscovered oil fields and 59.5% of undiscovered gas fields allocated 

to ONSHORE province) 

1.00

1.00

0.85

1.00
Stavropol-Prikumsk Total Petroleum System (110903), Middle Caspian Basin, Russia 25

Undiscovered Resources

MFS Prob. Oil (MMBO)

(0-1) F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

7 97 173 303 183 137 257 472 274 8 15 29 16

42 201 424 817 456 4 9 18 9

1.00 97 173 303 183 337 680 1,289 731 12 24 46 26

South Mangyshlak Total Petroleum System

3 122 246 449 261 150 359 821 406 6 14 33 16

18 208 466 899 499 5 11 23 12

1.00 122 246 449 261 359 825 1,720 905 11 26 57 29

3 182 369 673 391 225 539 1,232 609 9 21 50 24

18 313 700 1,348 749 7 17 35 19

1.00 182 369 673 391 538 1,238 2,580 1,357 16 39 85 43

Stavropol-Prikumsk Total Petroleum System

10 0 794 1,419 789 0 1,545 3,048 1,580 0 92 184 95

60 0 2,215 4,708 2,330 0 43 100 47

0.90 0 794 1,419 789 0 3,760 7,755 3,910 0 135 284 141

Gas (BCFG) NGL (MMBNGL)

1.00

1.00

1.00

0.90

South Mangyshlak (Entire) Assessment Unit (60% of undiscovered oil fields and 60% of undiscovered gas fields allocated to 

OFFSHORE province 1109) 

Offshore Prikumsk Zone Assessment Unit (100% of undiscovered oil fields and 100% of undiscovered gas fields allocated to 

OFFSHORE province 1109) 

Foreland Slope and Foredeep Assessment Unit (40.5% of undiscovered oil fields and 40.5% of undiscovered gas fields

allocated to OFFSHORE province) 

South Mangyshlak (Entire) Assessment Unit (40% of undiscovered oil fields and 40% of undiscovered gas fields allocated to 

ONSHORE province 1109) 

Table 1—Continued. Assessment results summary—allocated resources.

3 185 277 421 287 310 547 929 574 18 33 56 34

18 368 567 882 589 3 6 10 6

1.00 185 277 421 287 678 1,114 1,811 1,163 21 38 66 40

10 0 360 711 331 0 693 1,523 661 0 41 92 40

60 0 4,451 7,969 3,911 0 28 73 29

0.72 0 360 711 331 0 5,144 9,492 4,572 0 69 165 69

1.00

0.72

Onshore Stavropol-Prikumsk Assessment Unit (100% of undiscovered oil fields and 100% of undiscovered gas fields allocated to

ONSHORE province 1109) 

Central Caspian Offshore Assessment Unit (100% of undiscovered oil fields and 100% of undiscovered gas fields allocated to

OFFSHORE province 1109) 

Stavropol-Prikumsk Total Petroleum System 

(110903), Middle Caspian Basin, Russia

Introduction

The Stavropol-Prikumsk TPS is located in the northern part 

of the eastern North Caucasus region, just north of the TerekCaspian TPS (fig. 1). On the west, the petroleum system area 

includes the eastern slope and top of the Stavropol arch (fig. 9), 

whereas the western slope of the arch belongs to the neighboring 

Azov-Kuban basin. On the north, the system area is bounded by 

the uplift of the Karpinsky Ridge (fig. 2). The ridge is a late 

Paleozoic foldbelt covered by thin Mesozoic rocks. Closer to the 

Caspian Sea, thickness of the Mesozoic on the southern slope of 

the ridge increases and a number of hydrocarbon accumulations 

are present. This slope is included in the Stavropol-Prikumsk 

TPS. To the east, the TPS extends into the northwestern area of 

the central Caspian Sea and farther southeast into its central 

area. Only one prospect was recently drilled offshore and oil was 

tested; however, no detailed data are available. Limited seismic 

data of inferior quality are described in literature. Results of 

seismic surveys along regional profiles that were obtained by a 

consortium of Western companies in recent years are not publicly available. Therefore, the TPS boundaries offshore are conjectural. The inclusion of the central Caspian Sea area into the 

TPS is conditional and is based on supposed similarity of stratigraphic and, to a lesser extent, structural characteristics with the 

onshore TPS areas.
26 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

>700 1200 450 500 400 >1000 300

Cretaceous

0-200 0-600 0-300 100-200 450-550 300-400

Permian Triassic Jurassic

Upper

Upper Upper

Upper Lower

Lower Lower

Lower Middle

Middle

Kuman

Olenekian Anisian Ladinian Carnian Norian Rhaetian

Formation

Zurmutin

Zakum

Novokolod

Demyanov

Kultay

Aalenian

Bajocian

Bathonian

Callovian

Oxfordian

Kimmeridgian

Tithonian

Valanginian

Hauterivian

Barremian

Aptian

Albian

Neocomian

Cenomanian

Turonian

Coniacian

Santonian

Campanian

Maastrichtian

Neftekum Kizlyar Nogay

Jurassic

Pl

Neogene Paleogene

EOliMiPli

Figure 14. Columnar stratigraphic section of Mesozoic-Tertiary rocks of Stavropol-Prikumsk petroleum system (modified from Ulmishek and Harrison, 19

Induan

ShaleSandstoneConglomerate

Carbonates

VolcanicsCoal

Stratigraph

Regional se

Main reser

450-550 Thickness, 

EXPLANATION
Stavropol-Prikumsk Total Petroleum System (110903), Middle Caspian Basin, Russia 27

Original hydrocarbon reserves of the TPS are approximately 1.8 billion barrels of oil and 14 TCF of gas. Productivity 

has been established in a wide stratigraphic range, from the Triassic to the Miocene. The largest gas reserves are found in lower 

Maykop (Oligocene) sandstones in structural traps on the 

Stavropol arch and its slope. Discovered oil reserves are mostly 

in Triassic, Jurassic, and Cretaceous reservoirs in structural traps 

of the Prikumsk uplift (figs. 2, 9). The largest part of original 

reserves is in Aptian-Albian sandstone pays, but Triassic, Neocomian, and Upper Cretaceous carbonates and Middle Jurassic 

sandstones also contain many oil and gas condensate pools. 

Source rocks are present in the Triassic, Middle Jurassic, and 

Paleogene sections, but they are geochemically poorly characterized, and their relative endowment in hydrocarbon reserves is 

largely unknown.

Discovery History 

Deep drilling in the petroleum system area began after 

World War II. The giant (nearly 8 TCF) North Stavropol–Pelagiada gas field in the central part of the Stavropol arch was discovered in 1951, followed by discoveries of several gas fields in 

the same area in the late 1950’s. In the 1960’s and 1970’s, the 

main exploration efforts shifted to the east of the Stavropol arch, 

and several tens of oil and gas condensate fields of large to small 

size were discovered in Jurassic and Cretaceous reservoirs in 

structural traps of the Prikumsk uplift and Karpinsky Ridge. All 

sizable structures mapped in Jurassic and Cretaceous rocks were 

drilled during this time period, and attempts to explore for stratigraphic traps were largely unsuccessful. In the late 1970’s and 

later, deeper Triassic rocks became the principal exploration 

objective, and more than a dozen oil fields were found in structural and paleogeomorphic traps. Several oil fields were also 

found in self-sourced fractured shales in the lower part of the 

Maykop series. The first offshore prospect was recently drilled in 

the Severny area located close to the boundary between the 

Stavropol-Prikumsk and South Mangyshlak TPS (fig. 1), and a 

large oil and gas discovery was reported (The Wall Street Journal, 2000).

Oil and gas production in the area reached its peak in 1969–

1971, after which the decline in production started and continued 

until present.

Petroleum Occurrence

The principal gas reserves of the Stavropol-Prikumsk TPS 

are in structural traps on the Stavropol arch and in the westernmost part of the Prikumsk uplift. More than 90 percent of the 

reserves are in sandstone reservoirs of the lower Maykop Khadum Horizon (fig. 14). A few pools have been found in AptianAlbian sandstones. The gas is dry. Presently, gas reserves are 

essentially depleted.

The main oil-productive area is the Prikumsk uplift, which 

contains numerous isometric and variously elongated local structures. Nearly all structures are productive, but most fields are not 

large. Each field contains from one to six pays. Almost the entire 

sedimentary succession from the Triassic to the Miocene is 

productive. In Triassic rocks, larger pools are in carbonates of 

the Neftekum Formation (fig. 14), mainly in the zone of reef 

facies along the southern border of the East Manych trough (figs. 

2, 9). A few small pools have been found in carbonates of the 

Middle Triassic Kizlyar Formation. Most reservoirs contain oil.

The Middle Jurassic section contains about 20 pools in 

sandstone reservoirs. A few small pools have been found in the 

Lower Jurassic. Oil pools dominate in the more western areas, 

whereas gas condensate pools are found to the east. Similar areal 

distribution of oil and gas condensate is characteristic of Upper 

Jurassic and Lower Cretaceous rocks. The Upper Jurassic and 

Neocomian contain both sandstone and carbonate reservoirs. 

The Aptian-Albian clastic section contains the largest portion of 

TPS reserves. Most productive are lower Aptian sandstones, in 

which original daily yields of wells reached 2,000 barrels. The 

upper Aptian shale is a regional seal. In the northern areas, the 

seal becomes sandy, and leaks hydrocarbons, and younger 

Albian rocks are most productive (Klubov and Blokhina, 1988; 

Krylov, 1987). A few small oil pools have been found in Upper 

Cretaceous carbonate reservoirs.

Established productivity of Tertiary rocks of the Prikumsk 

uplift is limited. In the 1980’s, several oil pools were found in 

unconventional reservoirs. These pools are located in the western 

part of the Prikumsk uplift and the adjacent slope of the 

Stavropol arch. Reservoir rocks are organic-rich shales in the 

lower part of the Maykop series. Oil pools are substantially overpressured and controlled by zones of fracturing that are not 

related to local structures. Productivity of wells is highly variable and ranges from several to 800 b/d (Bochkarev and 

Ilchenko, 1986). Identification of prospects of this type is difficult because the reservoirs cannot be mapped by seismic surveys. Higher in the section, only a few small dry gas fields are 

found in sandstone beds of the middle Maykop series of the Prikumsk uplift.

About 20 gas condensate and oil fields are known north of 

the Prikumsk uplift. Most of these fields are on the southern 

slope of the eastern Karpinsky Ridge. All fields are small to 

medium in size. Almost entire reserves are found in AptianAlbian clastic reservoirs in structural traps. A few pools are 

present in Jurassic sandstones and Upper Cretaceous carbonates. 

Most fields are depleted.

An apparently large oil and gas discovery made offshore in 

the summer of 2000 is in a large structural trap. Productive are 

Middle Jurassic sandstones. Reported reserves are 2.2 billion 

barrels of oil equivalent of which 60 percent is oil (The Wall 

Street Journal, 2000). No further data on the discovery are available at this time.

Composition of oils and condensates of the Stavropol-Prikumsk TPS is diverse. Modern geochemical data that would 

allow correlation of oils with potential source rocks are lacking, 

and only data on group composition of oils and condensates and 

some gas chromatography data are available. From these data, 

Russian geologists identified two (Sokolov and others, 1990) or 

three (Vinogradova and others, 1985; Dzhabrailov and others, 

1991) families of oils.

Oils of the first family occur in lower Maykop, Upper Cretaceous, and uppermost Albian reservoirs at depths of 2,300–

2,900 m where reservoir temperatures are 115°–120° C. The oils 
28 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

Triassic rocks absent

Boundaries of large structures,

sawteeth toward structural lows

+++

Boundaries of smaller structures

Middle Caspian basin boundary

EXPLANATION

Elista

Arzgir

Graben

Horst

Uplift

V-M

Nalchik

Groznyi

^

^ ^ ^ ^

^ ^ ^ ^ ^ ^ ^ ^

^

^

^

^ ^ ^ ^ ^

^

^

^

^

^

^ ^

^

^

^

^

^

^ ^ ^

^

^

^

^

^ ^

^ ^

^

^

^

^

^

^ ^ ^

^

^

^

^

^

^

^

^

^ ^ ^ ^

^

^

^

^

^

^

^

^ ^ ^

^ ^ ^ ^

^

^ ^

^ ^ ^

^ ^ ^ ^ ^

^ ^ ^ ^

^ ^ ^ ^ ^

^

^

^

^

^

^

^

^

^ ^ ^

^

NORTH CASPIAN 

 BASIN

Figure 15. Structural map of Triassic taphrogenic sequence of eastern North Caucasus region (modified from Letavin, 1978). 

V-M, Velichaev-Maksimokum uplift. No scale. 

West Manych

Graben

Dadyn

East Manych Graben

Talov Terrace

Kuma - Nogay Zone

Berezkin Depression

Kuma River

Terek River

S

C

ea

aspian

Volga River

N
Stavropol-Prikumsk Total Petroleum System (110903), Middle Caspian Basin, Russia 29 

3000 4000 5000 6000 7000 

1000 2000

0

Oil and gas pools

0 15 30 

m EAST MANYCH KARP

 GRABEN

B

J

K1

K2

Pg-Mio

K

Krasny Kamyshan

Zakum Mezhozer

Ozek-Suat Plavnen

Mekteb Soyuz Zimnya Stavka

PRIKUMSK UPLIFT

Basement

Plio - Q

 NOGAYMONOCLINE

Tukuy

S Berezkin

Figure 16. Cross section through Stavropol-Prikumsk petroleum system (modified from Sokolov and others, 1990). Location of cross section shown in figure 9. 

, Paleozoic; 

, Triassic; J, Jurassic; K1, Lower Cretaceous; K2, Upper Cretaceous; Pg, Paleogene; Mio, Miocene; Plio, Pliocene; Q, Quaternary. 

III 

Fault

EXPLANATION











30 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

are relatively heavy (30°–38°API) and contain up to 0.3 percent 

sulfur and 7 percent asphaltenes. Solid paraffin content does not 

exceed 12 percent. The second family of oils occurs in Jurassic 

and Lower Cretaceous rocks. Most oils are found at depths of 

3,070–3,750 m under temperatures of 130°–150°C. These oils 

are lighter (37°–45° API) and less sulfurous, and they contain 

only 0.3–3.3 percent asphaltenes. The oils are highly paraffinic 

(to 30 percent) and are characterized by a pristane/phytane ratio 

greater than 2 and a cyclohexanes/cyclopentanes ratio of 0.4–

0.6. The third family includes oils reservoired in Triassic rocks. 

Most of the oils occur at depths of 3,400–5,000 m under temperatures of 140°–170° C. They are light, low-sulfur oils with high 

concentrations of solid paraffins (30–50 percent) and low resin 

and asphaltene contents. Pristane to phytane ratio ranges from 

1.1 to 1.5, and cyclohexanes are more abundant than cyclopentanes (average ratio 1.5). However, mixing of different oil types 

is common. In several fields, oils of the Triassic type occur in 

Jurassic and Cretaceous reservoirs, and some Triassic pools contain oils more similar to the Jurassic-Cretaceous type. Many 

compostional differences between oil types seem likely to have 

no genetic significance, and more data are needed to identify 

genetic oil families.

Stratigraphic Section

Maximum thicknesses of the Triassic sequence, which 

overlies the Paleozoic folded basement, are limited to grabens of 

the rift system (figs. 15, 16). The Upper Permian(?)–lower 

Induan Kuman Formation occurs at the base of the sequence 

(fig. 14). The formation comprises continental coarse red clastics in the lower part and marine gray clastics with thin carbonate beds in the upper part. The rest of the Lower Triassic is 

mostly a carbonate section on the Prikumsk uplift and basinal 

calcareous shales in the East Manych and Arzgir grabens. Middle Triassic through Carnian rocks are marine clastics with carbonate beds. The Norian-Rhaetian is unconformable over 

various older rocks, including the basement, and was formed 

after cessation of rifting. The section is mainly composed of 

calc-alkalic volcanics, including thick lava flows. The volcanics 

constitute a part of the extensive (about 4,000 km) Cimmerian 

volcanic arc related to a subduction zone on the southern active 

margin of Eurasia (Zonenshain and others, 1990). Maximum 

thicknesses of the volcanics (more than 1,000 m) are found in 

the Berezkin depression where older Triassic rocks are absent 

(fig. 15). To the north, the section is much thinner or absent 

because of pre-Jurassic erosion. On the Prikumsk uplift, various 

Triassic rocks subcrop at the pre-Jurassic unconformity.

The Lower Jurassic section is present chiefly on the 

Karpinsky Ridge and is formed by continental coaly clastics. 

Marine clastic rocks dominate in the Middle Jurassic. Lower–

Middle Jurassic and overlying Upper Jurassic and Neocomian 

rocks onlap the slope of the Stavropol arch and successively 

pinch out. Thin Aptian-Albian clastic rocks directly overlie the 

basement on the top of the arch. Upper Jurassic rocks are present 

only in the eastern areas of the TPS. They are mainly dolomites 

with increasing amounts of clastics to the west and anhydrites in 

the upper part of the section to the east. Unconformities are 

present at the bottom of the carbonate formation and at the top of 

the Kimmeridgian. Tithonian rocks are absent.

The Neocomian is composed of calcareous clastic rocks 

with carbonate beds in the Valanginian and Hauterivian. The 

section thins to the west and pinches out on the slope of the 

Stavropol arch. Aptian and Albian rocks are thick clastics. 

These rocks gradually become more shaly eastward. The Upper 

Cretaceous is about 200 m thick on the Stavropol arch and 

thickens to 400 m eastward and southeastward. It comprises 

various carbonate rocks, including limestone, marlstone, and 

chalk, with subordinate shale beds.

Paleocene-Eocene and Maykop series (Oligocene–lower 

Miocene) rocks unconformably overlie the Upper Cretaceous 

and are represented by two types of sections (Berlin and 

Ulmishek, 1978). The first type is developed on the Stavropol 

arch and is more similar to the sections of the adjacent AzovKuban basin west of the arch. The Paleocene-Eocene is thick 

(800-900 m) and is composed of shallow-water shales, siltstones, and sandstones. The overlying Maykop series is, on the 

contrary, relatively thin (600–700 m). It consists of basal sandstones of the Khadum Horizon (100–150 m thick) and overlying 

shales with thin sandstone and siltstone beds. The rest of the 

TPS area, including offshore, has the second type of section. 

The Paleocene-Eocene is a thin (50–100 m) condensed section 

of greenish-gray clayey limestones and calcareous shales 

deposited in a deep-water basin uncompensated by sediments 

(Berlin and Ulmishek, 1978). The section includes the upper 

Eocene Kuma Formation, a 20-m-thick bed of black organicrich marlstone accumulated in anoxic environments (fig. 14). 

The deep-water basin was filled by the Maykop series, which is 

1,200–1,400 m thick. The lower part of the series, including the 

Khadum Horizon, is composed of deep-water, organic-rich, 

anoxic black shales. Upward in the section, clastics are progressively more shallow-water in origin. Sandstone beds are present 

in the middle and upper part of the series in northeastern areas 

proximal to the provenance of coarse clastic material. The sandstones and interbedded shales form a series of prograding clastic wedges (clinoforms). Nine major clinoforms and 

corresponding sedimentary cycles are identified (Kunin and 

others, 1987). To the west and southwest, sandstones pinch out, 

and the section is almost exclusively composed of gray and 

black shales.

Middle–upper Miocene rocks unconformably overlie the 

Maykop series. The rocks are marine clastics with beds of 

coquina. Maximum thicknesses are in southeastern areas, and 

the section thins to the north and west. Upper Pliocene sediments occur at the top of the sedimentary cover.

Source Rocks

No modern geochemical data exist for source rocks of the 

TPS. However, indirect geologic and some geochemical data 

suggest that probable source rocks are present in several stratigraphic intervals. Distribution of oil and gas condensate fields 

in Triassic reservoir rocks of the Prikumsk uplift clearly indicates the presence of indigenous source rocks. Almost all wells 

were targeted at Neftekum Formation reef and back-reef carbonate reservoirs (fig. 14) of the Prikumsk uplift (Kuma-Nogay 

zone, and Velichaev-Maksimokum uplift in fig. 15). These shallow-water facies are commonly poor in organic matter; rare 
Stavropol-Prikumsk Total Petroleum System (110903), Middle Caspian Basin, Russia 31

DEPTH, IN METERS

0

2000400060008000

50 C 

100 C

150 C

200 C

AGE, IN MILLIONS OF YEARS

Early mature (oil)0.5 to 0.7 (%Ro)Mid mature (oil)0.7 to 1.0 (%Ro)Late mature (oil)1.0 to 1.3 (%Ro)Main gas generation1.3 to 2.6 (%Ro)

SandstoneSand and shaleShaleLimestoneBasement

EXPLANATION

300 200 100 

Kochubey 2

Figure 17. Maturation model for Kochubey 2 well, eastern part of Stavropol-Prikumsk total petroleum system. Approximate location of well sh

o

o

o

o

Permian Triassic Jurassic Cretaceous PalEoceneOligoMioce
32 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union Early mature (oil)

0.5 to 0.7 (%Ro)Mid mature (oil)0.7 to 1.0 (%Ro)Late mature (oil)1.0 to 1.3 (%Ro)Main gas generation1.3 to 2.6 (%Ro)

SandstoneSand and shaleShaleLimestoneBasement

0

20001000300040005000

300 200 100 

Gorokhov 9

Figure 18. Maturation model for Gorokhov 9 well, central part of Stavropol-Prikumsk total petroleum system. Approximate location of shown in figure 9.

DEPTH, IN METERS

AGE, IN MILLIONS OF YEARS

Permian Triassic Jurassic Cretaceous PalEoceneOligoMio

 EXPLANATION

50 C o

100 Co

150 Co
Stavropol-Prikumsk Total Petroleum System (110903), Middle Caspian Basin, Russia 33

shale beds have TOC not exceeding 3.5 percent (Mirzoev and 

Dzhaparidze, 1979). In the East Manych and Arzgir grabens, 

shallow-water carbonates of the Neftekum and Kultay Formations grade into thin-bedded, dark-colored, deep-water clayey 

limestones and shales (Letavin, 1988; Bochkarev and others, 

1992). Few wells have been drilled in the grabens, and cores are 

scarce. The principal Triassic source rocks are probably present 

among these deep-water facies (Klubov and Blokhina, 1988; fig. 

1). In the eastern part of the East Manych graben and farther east 

offshore, Triassic source rocks occur at depths of about 5 km and 

more. They reached the main oil-generation stage in Cretaceous 

time and entered the gas window during deposition of the Oligocene–lower Miocene Maykop series (fig. 17). Gas condensate 

pools are present in adjacent areas of the Prikumsk uplift. To the 

west, the source rocks occur at depths of 3.5–4 km and are presently in the oil window. Triassic reservoirs contain light oils 

there. Triassic source rocks are probably absent in the central 

Caspian area.

Higher in the section, source rocks are present in the 

Lower–Middle Jurassic section, but their geochemical characterization is insufficient for precise identification of specific favorable layers. Judging from lithologic descriptions, most probable 

source rocks occur in the lower Bajocian strata, which are composed of dark-gray and black marine shales containing ammonites and foraminifers (Letavin, 1988). The strata are about 200 

m thick in the eastern areas and pinch out to the west toward the 

Stavropol arch (fig. 1). Measured TOC in shales averages 1.15 

percent and reaches 3.2 percent in separate layers (Sokolov and 

others, 1990; Mirzoev and Dzhaparidze, 1979). Kerogen is of 

mixed types II and III; the latter is more abundant. The source 

rock section extends offshore and probably is present in the central Caspian part of the TPS, although the kerogen may be more 

coaly there. Bajocian source rocks are in the oil window over 

most of the onshore area. On the east of this area and probably 

offshore, the rocks the entered gas window in late Miocene time 

(fig. 17).

Many geologists believe that shale beds of the thick AptianAlbian marine clastic section have generated oil found in interbedded sandstone reservoirs. However, the source characteristics 

of the shales seem to be poor. The shales were deposited in suboxic environments; they are of dark-gray and greenish-gray color 

and include lenses and thin layers of siltstone. TOC in the shales 

averages 0.4–0.6 percent, and only in separate thin beds does it 

reach 1.5–2 percent. The kerogen is of mixed types II and III; 

type II is more abundant. The rocks reached early maturity in 

Oligocene–early Miocene time, during deposition of the Maykop 

series (figs. 17, 18). Presently they occur in the oil window over 

the entire area (Sokolov and others, 1990; Nazarevich and others, 1983). The contribution of Aptian-Albian source rocks in oil 

and gas reserves is probably insignificant, as also indicated by 

the apparent similarity of oils found in Jurassic and Cretaceous 

reservoirs.

Source rocks in the lower part of the Maykop series and 

underlying thin Paleocene-Eocene section (primarily the Kuma 

Formation—see fig. 14), which are so important in the TerekCaspian TPS, are also present in the Stavropol-Prikumsk TPS. 

The best source rocks are located in the upper part of the Khadum Horizon and directly overlying shale beds and are 30–40 

m thick. This section is formed by thin (1 mm–3 cm) alternation of black and gray shale layers. The rocks were deposited in 

a deep-water basin in strongly anoxic environments (Berlin and 

Ulmishek, 1978; Burlakov and others, 1987). TOC in black layers varies from 5 to 8 percent; in gray layers it does not exceed 

2 percent (Bochkarev and Ilchenko, 1986). Type II kerogen 

dominates in the source rocks. On the eastern slope of the 

Stavropol arch and western Prikumsk uplift, this section 

contains self-sourced overpressured oil pools in fractured 

shales. Fractures are oriented along sedimentary planes and are 

genetically related to hydrocarbon generation. Despite high reservoir temperatures (120°–130° C) the organic matter is at 

early stages of maturity corresponding to the upper and middle 

parts of the oil window (figs. 17, 18). Oils in these shales are 

highly naphthenic. They contain abundant isoprenoids, 6–11 

percent waxes, and 7–9 percent resins, and are characterized by 

odd/even n-alkanes predominance (Vinogradova and others, 

1989). 

On the Stavropol arch, the Khadum Horizon is composed of 

gas-bearing sandstones, and overlying and underlying organicrich shales are immature. They are also immature on the Karpinsky Ridge. Offshore, the source rocks extend over the entire 

petroleum system area. However, in the northern part of the offshore area, which is located toward the main provenance of clastic material (Onischenko, 1986), low source rock quality may be 

expected.

The role of Paleogene source rocks in productivity of older 

reservoirs is not clear because of scarcity of data. Compositional 

differences of Upper Cretaceous and uppermost Albian oils compared to oils in older Lower Cretaceous and Jurassic reservoirs 

may be related to different source rocks of the Paleogene and 

Middle Jurassic sections, respectively. Mixing of oils in these 

younger reservoirs from both sources is also probable.

In conclusion, the principal oil and gas condensate reserves 

of the TPS, which are concentrated on the Prikumsk uplift, were 

generated by at least three source rock formations in the Lower 

Triassic, Middle Jurassic, and Maykop series (fig. 19). Oil and 

gas condensate fields on the Karpinsky Ridge probably result 

from lateral migration of hydrocarbons from the Triassic and 

possibly Middle Jurassic sources of the East Manych trough. 

Large gas fields of the Stavropol arch were charged by longrange lateral migration from adjacent depressions, including 

those located in the Azov-Kuban basin. The principal stage of 

formation for all oil and gas fields of the TPS was during and 

after deposition of the thick Maykop series.

Reservoir Rocks

Productive reservoir beds are present through most of the 

TPS sedimentary section, from the Triassic to the Miocene. Several of these beds contain the bulk of oil and gas reserves; others 

only sporadically contain small pools. The principal Triassic pay 

that is productive in more than 10 fields consists of carbonate 

rocks of the Neftekum Formation (fig. 14). Most of these fields 

are located along the southern border of the East Manych trough 

(fig. 15) where the formation is largely composed of reef facies. 

Reservoir rocks are fractured vuggy limestones and dolomites. 
34 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union ROCK UNIT SOURCE ROCK RESERVOIR ROCK SEAL ROCK OVERBURDEN ROCK

TRAP FORMATION

GENERATIONPRESERVATION

CRITICAL MOMENT

PETROLEUM

SYSTEM EVENTS

GEOLOGIC TIME

SCALE

ACCUMULATION MIGRATION0

100

200

50

150

250

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65

144

248

206

E

E

E

E

M

M

L

L

L

L

Neogene

24

Pal

Eoc

Olig

Mio

Plio

Figure 19. Stavropol-Prikumsk petroleum system events chart. 
Stavropol-Prikumsk Total Petroleum System (110903), Middle Caspian Basin, Russia 35

Measured porosities reach 10 percent; permeability is completely 

controlled by fracturing (Stasenkov and others, 1983). Best reservoir rocks occur at the top of the formation under the unconformity surface; the rocks are commonly too friable to be cored.

In the Jurassic section, major oil and gas pays are Bajocian 

sandstones that have porosities of 12–16 percent and permeabilities to 100–150 mD. Eastward, the amount of clay material 

increases, and reservoir properties of the sandstones deteriorate. 

The Lower Cretaceous section contains 12 pays productive in 

different fields; most of the pays are sandstones. The principal 

reserves are concentrated in uppermost Barremian and lower 

Aptian sandstone beds. Another important producer is a sandstone bed at the top of the Albian. Porosity of the sandstones varies widely in different fields from 12 to 24 percent; permeability 

ranges from tens to hundreds of millidarcies.

Fractured shale reservoirs in the lower part of the Maykop 

series are poorly characterized by laboratory measurements. In 

situ porosity is evaluated at 10–12 percent (Klubova, 1988), and 

permeability is highly variable, as indicated by a wide range of 

initial oil flow rates. Sandstones and siltstones of the Oligocene 

Khadum Horizon, containing large gas accumulations on the 

Stavropol arch, possess excellent reservoir properties. Porosity 

reaches 40 percent, and permeability ranges from hundreds of 

millidarcies to several darcies.

Seal Rocks

The principal regional seal of the Stavropol-Prikumsk TPS, 

similarly to that of the Terek-Caspian TPS, is thick overpressured Maykop series shales. Above this seal, only a few small 

pools of dry gas, possibly of biogenic origin, are present. 

Although Maykop shales provide hydrodynamic isolation of the 

entire underlying sequence, they directly seal only gas pools on 

the Stavropol arch. Oil and gas pools in Mesozoic strata are 

sealed by various shale beds. Most important among them are 

thick and areally extensive shale beds in the upper Bajocian and 

upper Aptian, which seal most oil and gas reserves of the Prikumsk uplift.

Traps

The bulk of oil and gas reserves of the Stavropol-Prikumsk petroleum system are found in structural traps, although 

outlines of particular pools are often affected by lithologic 

changes of reservoir rocks. The number and characteristics of 

structural traps vary over the TPS area. Structural traps on the 

Stavropol arch that contain large gas accumulations are gentle, 

irregularly shaped uplifts underlain by basement highs. These 

traps were probably formed during Pliocene-Quaternary time 

when the arch was uplifted about 500 m (Shardanov and 

Romanov, 1988).

The Prikumsk uplift contains a large number of small to 

medium-size local structures. The structures are isometric or 

slightly elongated in various directions. Their closures are largest 

in Jurassic horizons and gradually decrease upward. In the western part of the uplift, the structures are traced upward to the bottom and locally to the top of the Maykop series. Toward the east, 

structural closures disappear in progressively older rocks. In 

areas adjacent to the Caspian Sea, the structures are present only 

in Jurassic rocks, whereas Cretaceous and younger rocks are 

undeformed. This situation may be expected to extend some distance offshore; however, large structural uplifts have been identified farther east, close to the eastern boundary of the petroleum 

system where recent discovery in the Severny area is located. 

Most local structures on the Prikumsk uplift are basementrelated, but apparently some are underlain by erosional highs at 

the top of the Triassic. The morphological characteristics of the 

traps suggest that they are old and were formed as drape structures, although slight posthumous structural growth could have 

occurred locally. Traps on the Karpinsky Ridge are similar to 

those on the Prikumsk uplift. Rocks filling the East Manych and 

Arzgir grabens are almost undeformed and few local structures 

are known there. The character of traps in Triassic rocks is 

poorly understood. Apparently, basement-related structural traps, 

reefs, and erosional highs under the pre-Jurassic unconformity, 

and combinations of those are present. 

Despite significant facies variability of clastic rocks, only 

several small pools have been found in stratigraphic traps related 

to up-dip pinchout of sandstone beds. Most of these pools occur 

in the Albian (Chepak, 1987). Probably, very little if any exploration specifically targeted at stratigraphic traps has taken place. 

Finally, traps for oil pools in shale reservoirs of the lower Maykop series are related to fracture zones. Discovered traps are 

located in depressions and on slopes of local uplifts. Fracturing 

was caused by hydrocarbon generation and associated increase 

of pore pressure. Some geologists believe that the location of the 

fracture zones is related to basement faults (Klubova, 1988), but 

little evidence exists.

Assessment Units

Three assessment units are identified in the Stavropol-Prikumsk TPS. Undiscovered oil and gas resources of these units 

are listed in table 1.

Assessment Unit 11090302, Onshore Stavropol-Prikumsk

 This unit covers the entire onshore area of the system (fig. 

1). The Stavropol arch on the west of the unit area (fig. 2) contains large, presently almost depleted gas fields. The arch is thoroughly explored, and the potential for new somewhat significant 

discoveries in structural traps is negligible. The Neocomian and 

lower Aptian sections onlap and thin updip on the eastern slope 

of the arch. Gas discoveries in stratigraphic traps are possible 

there, but the fields will probably be small. The rest of the assessment unit is also significantly explored. All known local uplifts 

in Jurassic and Cretaceous rocks have been drilled, and only 

small additional structural prospects can be found. However, 

there was little or no exploration specifically targeted at stratigraphic traps. Considering significant lithologic variability of 

many Jurassic and Cretaceous reservoir beds, a potential for 

stratigraphic hydrocarbon accumulations exists. However, 

mostly small fields can be expected.

Underlying Triassic rocks are significantly less explored 

and their geology is not well understood. Seismic resolution is 
36 Petroleum Geology, Resources—Middle Caspian Basin, Former Soviet Union 

poor, and only high-amplitude basement-related uplifts, which 

are also expressed in Jurassic and Cretaceous rocks, and Triassic 

erosional highs can be mapped. The presence of Lower Triassic 

reefs, basinal rocks, and associated facies suggests additional 

petroleum potential. On analogy with discovered fields, mainly 

oil accumulations will be found.

All discovered oil accumulations in fractured shales of the 

lower Maykop series were found accidentally in wells targeted 

at deeper horizons. The potential distribution of pools of this 

type is not clear, and seismic methods are inadequate to map 

prospects. However, relatively shallow depths and high oil quality can make exploration attractive. Mostly small size fields will 

be found, but their number may be significant. The exploration 

efficiency will increase as more data on distribution of fracture 

zones become available.

Assessment Unit 11090301, Offshore Prikumsk Zone 

This unit includes the offshore area into which the known 

onshore structures likely extend (fig. 1). Only one prospect has 

been drilled in the unit; therefore, risk related to possible 

changes in geologic characteristics should be included in 

resource assessment. The southeastern boundary of the unit is 

the inferred Agrakhan-Guryev strike-slip(?) fault (fig. 2). It is 

likely that the Triassic East Manych graben was connected with 

the Central Mangyshlak rift system of the same age and was offset along the strike-slip fault during the post-rift compressional 

stage. Thus, Lower Triassic source rocks and associated reef 

facies of the East Manych graben probably extend across the 

entire southern part of the assessment unit. The Lower–Middle 

Jurassic section that contains Bajocian source rocks onshore is 

certainly present over the entire assessment unit and is mature at 

least in its southern part. However, the quality of source rocks is 

likely to deteriorate eastward because the presence of source 

rocks, especially for oil, in this interval in the adjacent South 

Mangyshlak TPS is doubtful. Maykop source rocks might also 

be of poorer quality because of closer proximity to provenance 

for coarse clastic material. In the northern half of the assessment 

unit, the Maykop series is thin and certainly devoid of source 

rocks. Thus, the presence of source rocks can be expected only 

in the southern areas of the assessment unit. Updip migration of 

hydrocarbons into the more northern areas of the unit is possible, based on analogy with fields on the Karpinsky Ridge 

onshore. However, the exploration risk is higher.

Results of seismic work conducted offshore in recent years 

are not available, and information on the presence of structural 

traps is sparse. The Prikumsk uplift, which contains most of 

structural traps and major hydrocarbon reserves onshore, loses 

its structural expression in the nearshore area. In addition, basement-related local structures in the eastern part of the uplift are 

expressed only in Jurassic rocks, whereas younger beds are 

undeformed. Russian maps show several large structures in the 

eastern part of the assessment unit, but more detailed data are 

not available. Apparently, one of these structures in the Severny 

area that is located close to the boundary with the South Mangyshlak TPS produced the recent large discovery. This discovery 

was made after resource assessment of the Middle Caspian basin 

had been completed. If the size of the new field is confirmed, it 

raises chances for further significant discoveries, upgrades 

potential of the assessment unit, and eliminates risks that were 

included in the resource assessment.

Assessment Unit 11090303, Central Caspian Offshore 

This assessment unit occupies the central part of the Caspian Sea and is included in the Stavropol-Prikumsk TPS conditionally (fig. 1). No wells have been drilled, and data on only a 

few regional seismic profiles crossing the area are available. 

Based on these profiles, the unit area is occupied by a structural 

monocline descending southwestward to the Terek-Caspian 

foredeep. Depth to the basement varies from 3 to 6 km (Lebedev 

and others, 1987). To the southeast, the basement becomes shallower toward the Karabogaz arch. Comparison of the Jurassic 

through Tertiary rocks east and west of the Caspian Sea suggests 

that the stratigraphy of these rocks in the assessment unit is similar to that of the eastern Prikumsk uplift.

A risk involved in resource assessment of this unit is substantially higher than that for assessment unit 11090301. The 

risk is primarily related to the presence and quality of source 

rocks and traps. Unlike in the previous assessment unit, Triassic 

rifts and associated source rocks almost certainly do not extend 

into the area. The quality of Jurassic source rocks is uncertain. In 

general, the rocks become more continental and gas-prone eastward. Source rocks at the bottom of the Maykop series are 

present, but they are probably immature in the southeastern part 

of the unit. In the rest of the unit area, the feasibility of migration 

of hydrocarbons from Maykop source rocks to the principal 

Jurassic and Lower Cretaceous reservoirs is doubtful because 

mostly gentle, platform-type structures can be expected. Many 

of these structures might be open updip on the monocline. 

Larger structural traps have been mapped in the southeastern 

part of the unit, on the flank of the Karabogaz arch, but source 

rocks in this area are absent, and exploration should rely upon 

possible long-range lateral migration. Gas is more likely hydrocarbons in these traps. Stratigraphic traps updip of the monocline in Jurassic–Lower Cretaceous and possibly middle 

Miocene rocks are probable, but most fields will be small. In 

conclusion, petroleum potential of the assessment unit is probably rather low.

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